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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 (Fee Required)
For the fiscal year ended December 31, 1995
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934 (No Fee Required)
Commission File Number 1-10874
MESA Inc.
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(Exact Name of Registrant as Specified In Its Charter)
Texas 75-2394500
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(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification Number)
1400 Williams Square West
5205 North O'Connor Boulevard
Irving, Texas (214) 444-9001 75039-3746
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(Address of Principal (Registrant's (Zip Code)
Executive Offices) Telephone Number)
Securities registered pursuant to Section 12(b) of the Act:
Name of Each Exchange
Title of Each Class on Which Registered
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Common stock, $.01 par value........................ New York Stock Exchange
Preferred Stock Purchase Rights......................New York Stock Exchange
13-1/2% Subordinated Notes due May 1, 1999.......... New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. YES X NO
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Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form
10-K or any amendment to this Form 10-K. [X]
Number of shares outstanding as of the close of business on March 6,
1996: 64,050,009.
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Aggregate market value of 56,833,524 shares held by non-affiliates of
Registrant at the closing price on March 6, 1996, of $2.875: approximately
$163.4 million.
DOCUMENTS INCORPORATED BY REFERENCE
None
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<PAGE>
TABLE OF CONTENTS
PART I
Item 1. Business
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Submission of Matters to a Vote of Security Holders
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Item 8. Consolidated Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
PART III
Item 10. Directors and Executive Officers of the Registrant
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management
Item 13. Certain Relationships and Related Transactions
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
Signatures
<PAGE>
PART I
Item 1. Business
=================
The Company
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MESA Inc. is one of the largest independent oil and gas companies in
the United States and considers itself one of the most efficient operators
of domestic natural gas producing properties and natural gas processing
facilities. MESA has been publicly traded since 1964 and is primarily in
the business of exploring for, developing, producing, processing and selling
natural gas and oil in the United States.
As of December 31, 1995, MESA owned approximately 1.9 trillion cubic
feet of equivalent proved natural gas reserves ("Tcfe"). Approximately 65%
of MESA's total equivalent proved reserves is natural gas and the balance is
principally natural gas liquids ("NGLs"), which are extracted from natural
gas through processing plants. Substantially all of MESA's proved reserves
are proved developed reserves. Quantities stated as equivalent natural gas
reserves are based on a factor of six thousand cubic feet ("Mcf") of natural
gas per barrel ("Bbl") of liquids. See "-- Reserves."
MESA's principal business strategies include (i) maximizing the value
of its existing high-quality, long-life reserves through efficient operating
and marketing practices, (ii) processing natural gas to extract value-added
products such as NGLs and helium, (iii) conducting selective exploratory and
development activities, principally in existing areas of operations, (iv)
making acquisitions of producing properties with exploration and development
potential in areas where MESA has operating experience and expertise, (v)
generating value and cash flow from investments in natural gas and other
energy futures contracts, and (vi) promoting the use of compressed and
liquefied natural gas as a transportation fuel.
MESA Inc. (the "Company") is a holding company and conducts its
operations through its subsidiaries. Unless the context otherwise requires,
the term "MESA" means the Company and its subsidiaries taken as a whole and
includes the Company's predecessors, Mesa Limited Partnership (the
"Partnership") and Mesa Petroleum Co. ("Original Mesa"). MESA maintains its
principal offices at 1400 Williams Square West, 5205 North O'Connor
Boulevard, Irving, Texas 75039-3746, where its telephone number is (214)
444-9001. At December 31, 1995, MESA employed 385 employees.
Financial Condition, Liquidity and Exploration of Strategic Alternatives
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MESA has a highly leveraged capital structure with long-term debt,
including current maturities, totaling approximately $1.2 billion at
December 31, 1995. MESA's current financial forecasts indicate, assuming no
changes in capital structure and no significant transactions are completed,
that cash generated by operating activities, together with available cash
and investment balances, will not be sufficient to make all of its required
debt principal and interest obligations due in June 1996.
In an effort to address its liquidity issues, MESA's Board of Directors
(the "Board") approved a proposal solicitation process which started in late
1994 and was expanded in mid-1995. The process has included solicitation of
proposals for a sale of MESA, a stock-for-stock merger, joint ventures,
asset sales, equity infusions, and refinancing transactions.
On February 28, 1996, MESA signed a letter of intent with Rainwater,
Inc. ("Rainwater"), an independent investment company owned by Ft. Worth,
Texas, investor Richard Rainwater, to raise $265 million of equity in
connection with a refinancing of MESA's debt. The transaction, more fully
described in the "Capital Resources and Liquidity" section of "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
located elsewhere in this Form 10-K, is subject to certain conditions,
including definitive agreements, arrangement of new debt financing, due
diligence, and MESA stockholder approval. The parties anticipate executing
definitive agreements in approximately 30 days. The transaction will be
submitted to a vote of stockholders at a special meeting expected to take
place in June 1996.
The ability of MESA to continue as a going concern is dependent upon
several factors. The successful completion of the Rainwater transaction is
expected to position MESA to continue as a going concern and to pursue its
business strategies. If the Rainwater transaction is not completed, MESA
will pursue other alternatives to address its liquidity issues and financial
condition, including other potential transactions arising from the proposal
solicitation process, the possibility of seeking to restructure its balance
sheet by negotiating with its current debt holders or seeking protection
from its creditors under the Federal Bankruptcy Code.
For additional information regarding the Rainwater transaction and
MESA's financial position, see Notes 2 and 4 to the consolidated financial
statements of the Company and "Management's Discussion and Analysis of
Financial Condition and Results of Operations" included elsewhere in this
Form 10-K.
Properties
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Approximately 95% of MESA's proved reserves are concentrated in the
Hugoton field of southwest Kansas and the West Panhandle field of Texas.
The two fields are each part of a reservoir that extends from southwest
Kansas, through the Oklahoma panhandle, and into the Texas panhandle. These
fields, which produce gas from depths of 3,500 feet or less, are known for
their stable long-life production profiles. MESA's other properties are
primarily in the Gulf of Mexico and the Rocky Mountains.
In recent years MESA has concentrated its efforts on fully developing
its existing long-life reserve base and improving its marketing flexibility.
In the Hugoton field, these efforts have included infill drilling (i.e.,
drilling an additional well on each 640-acre spacing unit), installing
additional compression and gathering facilities, and the construction of a
new natural gas processing plant, which has the ability to extract a greater
quantity of NGLs per Mcf of natural gas, reject nitrogen and produce crude
helium. The new plant also has the capability to liquefy natural gas. Two
significant gas sales contracts related to Hugoton production expired in May
1995, giving MESA a substantial amount of uncommitted deliverability
available for sale after that date. In the West Panhandle field,
development activities have included well workovers and deepenings/redrills,
adding compression facilities, and the expansion and upgrading of natural
gas processing facilities to process greater quantities of natural gas and
produce crude helium. In addition, MESA restructured its contractual
arrangements in the West Panhandle field to more clearly define its right to
production and to create greater marketing flexibility. Beginning in late
1994 MESA began to direct a greater portion of its capital spending towards
exploration and development in the Gulf of Mexico.
MESA's strategies for replacing reserves and increasing production are
based on a multi-step approach, including (i) development and exploratory
drilling in the Gulf of Mexico based on evaluation of three- dimensional
("3-D") seismic data, (ii) developing additional reserves in certain deeper
portions of the West Panhandle field reservoir, and (iii) acquisitions of
new leases and producing properties with development and exploration
potential, particularly in areas where MESA presently or historically has
operated. The extent to which MESA pursues these activities is largely
dependent on the success of its proposal solicitation process and the amount
of cash flow available for capital spending after such process is complete.
MESA has maintained a large geological and geophysical database
covering the Midcontinent and other areas where it has historically
operated. As capital becomes available and conditions permit, MESA intends
to exploit its database and consider selective acquisitions of producing
properties with development and exploration potential in the Texas
Panhandle, the Hugoton field, and other areas of the Midcontinent and Gulf
Coast regions.
Hugoton Field
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The Hugoton field in southwest Kansas began producing in 1922, and is
the largest producing gas field in the continental United States. MESA's
Hugoton properties, which represent approximately 13% of the proved reserves
in the field, are concentrated in the center of the field on over 230,000
net acres, covering approximately 400 square miles. MESA produces natural
gas from approximately 1,400 wells (950 of which are operated by MESA) on
these properties. MESA owns substantially all of the gathering and
processing facilities which service its production from the Hugoton field
and which allow MESA to control the production stream from the wellbore to
the various interconnects it has with major intrastate and interstate
pipelines.
MESA's Hugoton properties are capable of producing more than 230
million cubic feet ("MMcf") of wet gas per day (i.e., gas production at the
wellhead before processing and before reduction for royalties).
Substantially all of MESA's Hugoton production is processed through its
Satanta natural gas processing plant (the "Satanta Plant"). After
processing, on a peak production day, MESA has available to market over 150
MMcf of residue (processed) gas and 13 thousand barrels ("MBbls") of NGLs.
Production in the Hugoton field is subject to allowables set by state
regulators.
MESA's Hugoton properties accounted for approximately 64% of its
equivalent proved reserves and 63% of the present value of estimated future
net cash flows before income taxes, determined as of December 31, 1995, in
accordance with Securities and Exchange Commission (the "Commission")
guidelines. The Hugoton properties accounted for approximately 47%, 53%,
and 48% of MESA's oil and gas revenues for the years ended December 31,
1995, 1994, and 1993, respectively. The percentage of revenues from the
Hugoton field has been less than the percentage of equivalent proved
reserves due primarily to the longer life of the Hugoton properties compared
to MESA's other properties. See "Production--Hugoton Field."
West Panhandle Field
--------------------
The West Panhandle properties are located in the northern panhandle
region of Texas, and are geologically similar to MESA's Hugoton properties.
Natural gas from these properties is produced from approximately 600 wells
which MESA operates on over 185,000 net acres. All of MESA's West Panhandle
production is processed through MESA's Fain natural gas processing plant
(the "Fain Plant").
MESA's West Panhandle reserves are owned and produced pursuant to
contracts with Colorado Interstate Gas Company ("CIG"), originally executed
in 1928 by predecessors of both companies. An amendment to these contracts,
the Production Allocation Agreement ("PAA"), allocates 77% of the production
from the West Panhandle field properties to MESA and 23% to CIG, effective
as of January 1, 1991. Under the associated agreements, MESA operates the
wells and production equipment and CIG owns and operates the gathering
system by which MESA's production is transported to the Fain Plant. CIG
also performs certain administrative functions. Each party reimburses the
other for certain costs and expenses incurred for the joint account.
As of December 31, 1995, MESA's West Panhandle properties represented
approximately 32% of MESA's equivalent proved reserves, and approximately
32% of the present value of estimated future net cash flows before income
taxes, determined in accordance with Commission guidelines. Production from
the West Panhandle properties accounted for approximately 33%, 36%, and 40%
of MESA's oil and gas revenues for the years ended December 31, 1995, 1994,
and 1993, respectively. Although the West Panhandle properties are long-
lived, the percentage of MESA's revenues represented by West Panhandle
production has been greater than the percentage of equivalent proved
reserves represented by such properties. This is a result of higher gas
prices received under a sales contract for approximately 29% of MESA's West
Panhandle residue gas production, as well as the higher yield of NGLs
extracted from West Panhandle natural gas as compared to Hugoton natural
gas.
The Fain Plant is capable of processing up to 120 MMcf of natural gas
per day. West Panhandle field natural gas contains a high quantity of NGLs.
As a result, processing this gas yields relatively greater liquid volumes
than recoveries typically realized in other natural gas fields. For
example, on a peak day, MESA can extract approximately 12 MBbls of NGLs at
its Fain Plant from an inlet gas volume of 120 MMcf.
In the last six years MESA has deepened, redrilled, or reworked 357
wells in the West Panhandle field, adding reserves, and increasing
deliverability. MESA has also identified in excess of 100 drilling
locations targeting reserves in deeper portions of the reservoirs not
currently reached by existing wells. MESA will commence an active three-
year program to develop these reserves in 1996 in anticipation of its
contractual right to increase its share of West Panhandle production in 1997
and thereafter. See "Production--West Panhandle Production".
Gulf Coast
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MESA's Gulf Coast properties are located offshore Texas and Louisiana.
MESA has operated in the Gulf of Mexico since 1970 and has produced
approximately 425 billion cubic feet of equivalent natural gas ("Bcfe") (net
to MESA's interest). MESA currently owns interests in 45 blocks in the Gulf
of Mexico. As of December 31, 1995, these properties had an estimated 53
Bcfe of remaining proved reserves. In addition, MESA has over 100,000 miles
of two-dimensional ("2-D") seismic data and over 350 square miles of 3-D
seismic data in the Gulf of Mexico. MESA has an office in Lafayette,
Louisiana, to oversee production from its Gulf Coast properties. MESA's
working interests in seven of its 45 blocks are subject to a net profits
interest owned by the Mesa Offshore Trust.
Over the last five years, MESA has evaluated a number of its offshore
producing properties utilizing well information, 2-D seismic and production
data, combined with 3-D seismic surveys to identify further development and
exploration potential. MESA currently has 10 3-D seismic surveys under
analysis. New well locations were identified on five producing leases in
1995 and one exploratory block was acquired based upon interpretation of
3-D seismic data. In 1994 and 1995, MESA drilled or participated in 14
wells in the Gulf Coast area based on 3-D seismic surveys of which 12 were
completed as successful wells. In the aggregate, MESA incurred net capital
costs of $36 million during this period and added approximately 51 Bcfe of
oil and gas reserves. MESA intends to continue its evaluation and
identification of additional prospects for drilling in 1996, depending on
the success of its program and other factors. Because it has existing
infrastructure and production facilities on these properties, MESA expects
that it will be able to bring its successful wells on-line more quickly and
at lower development costs than have been typical for offshore production.
Other
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MESA's other producing properties are located in the Rocky Mountain
area of the United States.
MESA's non-oil and gas tangible properties include buildings, leasehold
improvements, and office equipment, primarily in Amarillo, Dallas, and Fort
Worth, Texas, and certain other assets. Non-oil and gas tangible properties
comprise less than 2% of the net book value of MESA's properties.
Reserves
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The following table summarizes the estimated proved reserves and
estimated future cash flows as estimated in accordance with Commission
guidelines associated with MESA's oil and gas properties as of December 31,
1995, by major areas of operation (dollar amounts in thousands):
West Gulf
Hugoton Panhandle Coast Other Total
--------- --------- -------- -------- ---------
Proved Reserves:
Natural Gas (MMcf)... 863,939 283,218 38,317 32,555 1,218,029
Natural Gas Liquids
(MBbls)............. 56,720 45,041 122 14 101,897
Oil (MBbls).......... -- 6,817 2,303 401 9,521
Natural Gas
Equivalents (MMcfe). 1,204,259 594,366 52,867 35,045 1,886,537
Future Net Cash Flows,
before income taxes
(in thousands)..........$1,693,307 $682,714 $41,704 $32,095 $2,449,820
Present Value of Future
Net Cash Flows, Before
Income Taxes,
Discounted at 10%
(in thousands)..........$ 658,330 $332,353 $40,716 $ 9,014 $1,040,413
The proved reserve estimates set forth above were prepared by MESA's
engineers. Prior to 1994 MESA's proved reserve estimates were prepared by
an independent petroleum engineering firm. In accordance with a long-term
debt agreement, the independent petroleum engineering firm will prepare
proved reserve estimates as of December 31, 1995, covering MESA's Hugoton
properties in the manner and to the extent required by the debt agreement.
Their report is not yet available and will not be used for purposes other
than those prescribed in the debt agreement. MESA expects, as in prior
years, that the Hugoton field reserve estimates prepared by such independent
engineers will be less than those of MESA's engineers due to the independent
engineers' different interpretation of well-test pressure and cumulative
production data related to MESA's Hugoton field properties. Such
differences have been substantial in previous years. MESA has received
preliminary indications from the independent engineers that their reserve
estimates for the Hugoton field will reflect a downward revision from prior
estimates by such engineers and, as a result, such estimates may be as much
as 25% less than MESA's estimates of Hugoton field reserves as of December
31, 1995. See Note 4 to the consolidated financial statements of the Company
located elsewhere in this Form 10-K for additional discussion of the
independent engineers' reserve report.
Oil and gas reserve quantities estimated as of December 31, 1995,
reflect a net increase over 1994, after production, of approximately 171
Bcfe of natural gas. Equivalent natural gas reserves increased in each of
MESA's major production areas. Increases in Hugoton field reserves reflect
alignment of the assumptions used in preparing the proved reserve estimates
with MESA's practice of recovering ethane at the Satanta Plant. In previous
years Hugoton proved reserve estimates were prepared assuming that MESA
would not recover ethane which resulted in slightly higher natural gas
volumes, lower NGL volumes and lower total equivalent volumes than if ethane
recovery were assumed. The decision as to whether or not to recover ethane
is based on the relative value of ethane as a liquid versus the energy-
equivalent value of such ethane if left in the residue natural gas. In the
future, if economic conditions warrant, MESA may revise proved reserves to
reflect any changes in such relative values. In the West Panhandle field,
reserves were revised upward to reflect the development drilling results
over the past year and the planned upgrade of the Fain Plant for a higher
rate of liquids recovery per Mcf of gas produced from the field. In the
Gulf Coast, reserve additions resulted from exploratory and development
drilling in 1994 and 1995.
Reserve engineering is not an exact science. Information relating to
MESA's proved oil and gas reserves is based upon engineering estimates.
Estimates of economically recoverable oil and gas reserves and of future net
revenues depend upon a number of factors and assumptions, such as historical
production performance, the assumed effects of regulations by governmental
agencies and assumptions concerning future oil and gas prices, future
operating costs, severance and excise taxes, development costs and workover
costs, all of which may in fact vary considerably from actual future
conditions. The accuracy of any reserve estimate is a function of the
quality of the available data, of engineering and geological interpretation
and of subjective judgment. For these reasons, estimates of the
economically recoverable quantities of oil and gas reserves attributable to
any particular group of properties, classifications of such reserves based
on risk of recovery and estimates of the future net revenues expected
therefrom prepared by different engineers or by the same engineers at
different times may vary materially. Actual production, revenues, and
expenditures with respect to MESA's reserves will likely vary from
estimates, and such variances may be material.
During 1995, MESA filed Form EIA-23, which included reserve estimates
as of December 31, 1994, with the Energy Information Administration of the
Department of Energy (the "EIA"). Such reserve estimates did not vary from
those estimates contained herein by more than 5% as described above.
The estimated quantities of proved oil and gas reserves, the
standardized measure of future net cash flows from proved oil and gas
reserves (the "Standardized Measure") and the changes in the Standardized
Measure for each of the three years in the period ended December 31, 1995,
are included under "Supplemental Financial Data" in the notes to the
consolidated financial statements of the Company located elsewhere in this
Form 10-K.
Production
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MESA's Hugoton and West Panhandle fields are both mature reservoirs
that are substantially developed and have long-life production profiles.
Natural gas production is subject to numerous state and federal laws
and Federal Energy Regulatory Commission (the "FERC") regulations. See
"Regulation and Prices" below.
Certain factors affecting production in MESA's various fields are
discussed in greater detail below.
Hugoton Field
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The Kansas Corporation Commission (the "KCC") is the state regulatory
agency that regulates oil and gas production in Kansas. One of the KCC's
most important responsibilities is the determination of market demand
(allowables) for the field and the allocation of allowables among the more
than 9,000 wells in the field.
Twice each year, the KCC sets the fieldwide allowable production at a
level estimated to be necessary to meet the Hugoton market demand for the
summer and winter production periods. The fieldwide allowable is then
allocated among individual wells determined by a series of calculations that
are principally based on each well's pressure, deliverability, and acreage.
The allowables assigned to individual wells are affected by the relative
production, testing, and drilling practices of all producers in the field,
as well as the relative pressure and deliverability performance of each
well.
Generally, fieldwide allowables are influenced by overall gas market
supply and demand in the United States as well as specific nominations for
gas from the parties who produce or purchase gas from the field. Since
1987, fieldwide allowables have increased in each year except 1991. The
total field allowable in 1995 was 619 billion cubic feet ("Bcf") of wellhead
gas.
In 1994 the KCC issued an order establishing new field rules which
modified the formulas used to allocate allowables among wells in the Chase
formation portion of the Hugoton field. The standard pressure used in each
well's calculated deliverability was reduced by 35%, greatly benefitting
MESA's high deliverability wells. Also, the new rules assign a 30% greater
allowable to 640-acre units with infill wells than to similar units without
infill wells. Substantially all of MESA's Hugoton infill wells have been
drilled. MESA's share of the allowables from the field increased from
approximately 10% in late 1993 to approximately 14% after the new field
rules were implemented in 1994. MESA's share of the field allowable
averaged 14.3% in 1995. MESA estimates that it and the other major producers
in the Hugoton field produced at or near full capacity in 1995 and MESA
expects such practice to continue.
MESA's net Hugoton field production decreased to approximately 70 Bcfe
in 1995 compared with 73 Bcfe in 1994 as a result of changes in timing and
duration of equipment maintenance in 1995. MESA expects its Hugoton field
production will decline slightly from 1995 levels each year through 1998.
Beginning in 1999, MESA expects annual production declines will reach the
historical levels of 8% to 10% as a result of normal depletion.
Excluding reserve acquisitions, MESA has invested over $138 million in
capital expenditures in its Hugoton properties since 1986 to drill 382
infill wells, to construct the Satanta Plant and related facilities, and to
upgrade gathering and compression facilities, production equipment and
pipeline interconnects in order to increase production capacity and
marketing flexibility. MESA expects future capital expenditures to be
substantially lower.
West Panhandle Field
--------------------
MESA's production of wet gas from the West Panhandle field is governed
by the PAA and other contracts with CIG. MESA was entitled to take wet gas
production up to a maximum of 32 Bcf in 1995. MESA actually took 29 Bcf
primarily due to a weather-related decrease in demand in 1995. MESA will
again be entitled to take wet gas production up to a maximum of 32 Bcf
during 1996. After deductions for processing and royalties, MESA expects
that 32 Bcf of wet gas production will result in annual net production
volumes of approximately 21 Bcf of residue gas and 3 million barrels
("MMBbls") of NGLs. Beginning in 1997 MESA will have the right to take and
market as much gas as it can produce, subject to specific CIG seasonal and
daily entitlements as provided for under the contracts. Assuming
continuation of existing economic and operating conditions, MESA expects its
existing West Panhandle properties will be able to produce an average of 35
Bcf of wet gas per year for sale in the years 1997 through 2000.
The PAA contains provisions which allocate 77% of ultimate production
after January 1, 1991, to MESA and 23% to CIG. As a result, MESA records
77% of total annual West Panhandle production as sales, regardless of
whether MESA's actual deliveries are greater or less than the 77% share.
The difference between MESA's 77% entitlement and the amount of production
actually sold by MESA to its customers is recorded monthly as production
revenue with corresponding accruals for operating costs, production taxes,
depreciation, depletion and amortization, and gas balancing receivables. At
December 31, 1995, MESA had cumulative production which was less than its
77% entitlement since January 1, 1991, and a long-term gas balancing
receivable of $42.6 million was recorded in MESA's balance sheet in other
assets. In future years, as MESA sells to customers more than its 77%
entitlement share of field production, this receivable will be realized.
See "-- Production Allocation Agreement" in "Management's Discussion
and Analysis of Financial Condition and Results of Operations" located
elsewhere in this Form 10-K.
Natural Gas Processing
- ----------------------
MESA processes its natural gas production for the extraction of NGLs
and helium to enhance the market value of the gas stream. In recent years
MESA has made substantial capital investments to enhance its natural gas
processing and helium extraction capabilities in the Hugoton and West
Panhandle fields. MESA owns and operates its processing facilities, which
allows MESA to (i) capture the processing margin for itself, as third-party
processing agreements generally available in the industry result in
retention of a significant portion of the processing margin by the contract
processor, (ii) control the quality of the residue gas stream, permitting it
to deliver gas directly to pipelines for sales to local distribution
companies, marketing companies, and end users, and (iii) realize value from
premium products such as helium. MESA believes that the ability to control
its production stream from the wellhead through its processing facilities to
disposition at central delivery points enhances its marketing opportunities
and competitive position in the industry.
Through its natural gas processing plants, MESA extracts raw NGLs and
crude helium from the wet natural gas stream. The NGLs are then transported
and fractionated into their constituent hydrocarbons such as ethane,
propane, normal butane, isobutane, and natural gasolines. The NGLs and
helium are then sold pursuant to contracts providing for market-based
prices.
Satanta Natural Gas Processing Plant
------------------------------------
The Satanta Plant has the capacity to process 250 MMcf of natural gas
per day, and enables MESA to extract NGLs from substantially all of the gas
produced from its Hugoton field properties as well as third party producers'
gas. The Satanta Plant also has the ability to extract helium from the gas
stream. In 1995 the Satanta Plant averaged 191 MMcf per day of inlet gas
and produced a daily average of 10.9 MBbls of NGLs, 671 Mcf of crude helium,
and 144 MMcf of residue natural gas.
Fain Natural Gas Processing Plant
---------------------------------
Wet gas produced from the West Panhandle field contains a high quantity
of NGLs, yielding relatively greater NGL volumes than realized from most
other natural gas fields. The Fain Plant has inlet capacity of 120 MMcf per
day. In 1995 the Fain Plant averaged 81 MMcf per day of inlet gas and
produced a daily average of 8.1 MBbls of NGLs and condensate, 53 Mcf of
crude helium, and 61 MMcf of residue natural gas.
MESA plans to expand the Fain Plant to process additional natural gas
production which MESA expects to take beginning in 1997 and to process
certain third-party natural gas. MESA also plans to upgrade the Fain Plant
to recover additional liquids from the natural gas stream due to richer gas
in the field.
Sales and Marketing
- -------------------
Following the processing of wet gas, MESA sells the dry (or residue)
natural gas, helium, condensate, and NGLs pursuant to various short- and
long-term sales contracts. Substantially all of MESA's gas and NGL sales
are made at market prices, with the exception of certain West Panhandle
field volumes. Due to a number of market forces, including the seasonal
demand for natural gas, both sales volumes from MESA's properties and sales
prices received vary on a seasonal basis. Sales volumes and price
realizations for natural gas are generally higher during the first and
fourth quarters of each calendar year.
See "Revenues" in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" located elsewhere in this Form 10-K for
a table showing production and prices by area for the past three years.
Hugoton Gas Sales Contracts
---------------------------
A substantial portion of MESA's Hugoton field production was subject to
two gas purchase contracts with Western Resources, Inc. ("WRI") and Missouri
Gas Energy ("MGE") which expired in May 1995. Under the contracts, WRI and
MGE had the right to purchase 19.9 Bcf during the first five months of 1995
at market prices. In 1995 WRI and MGE together purchased 20.7 Bcf of gas
from MESA at an average price of $1.44 per Mcf under these contracts. Since
June 1, 1995, gas previously subject to the WRI and MGE contracts has been
sold to multiple purchasers including WRI and MGE under short-term contracts
at market prices.
MESA's efforts to maximize its annual production and to direct natural
gas sales to the most favorable markets available are consistent with
regulatory and contractual requirements. MESA sells its Hugoton field
production to marketers, pipelines, local distribution companies, and
end-users, generally at market prices.
West Panhandle Gas Sales Contracts
----------------------------------
Most of MESA's West Panhandle field residue natural gas is sold
pursuant to gas purchase contracts with two major customers in the Texas
panhandle area.
Approximately 9 Bcf per year of residue natural gas is sold to a gas
utility that serves residential and commercial customers in Amarillo, Texas,
under the terms of a long-term agreement dated January 2, 1993, which
supersedes the original contract that was in effect since 1949. The
agreement contains a pricing formula for the five-year period from 1993
through 1997 whereby 70% of the volumes sold to the gas utility are sold at
fixed prices and the other 30% of volumes sold are priced at a regional
market index based on spot prices plus $.10 per Mcf. The fixed portion of
the price formula was $2.85 per Mcf in 1994, $2.99 per Mcf in 1995 and
escalates to $3.21 per Mcf in 1996 and $3.45 per Mcf in 1997. Prices for
1998 and beyond will be determined by renegotiation. MESA provides the gas
utility significant volume flexibility, including a right to the residue gas
volumes required to meet the seasonal needs of its residential and
commercial customers. The average price received by MESA for natural gas
sales to the gas utility in 1995 was $2.55 per Mcf.
Through 1995, MESA's principal industrial customer for West Panhandle
field gas was an intrastate pipeline company which serves various markets,
including an electric power-generation facility near Amarillo. In 1990 MESA
entered into a five-year contract with the pipeline company to supply gas to
the power generation facility. The contract provided for a minimum annual
volume of 8.4 Bcf in 1995 at a fixed price per million British thermal units
("MMBtu") of $1.70 in 1995. MESA periodically made sales to the pipeline
company in excess of the minimum volumes specified in the contract at market
prices. In 1995 MESA sold approximately 9.3 Bcf of residue natural gas to
the pipeline for an average price of $1.63 per Mcf. This contract expired
on December 31, 1995.
Effective January 1, 1996, MESA entered into a four-year contract with
a marketing company, an affiliate of the intrastate pipeline company, which
serves the local electric power-generation facility and various other
markets within and outside Amarillo, Texas. The contract provides for the
sale of MESA's West Panhandle field gas which is in excess of the volumes
sold to the gas utility and other existing industrial customers. The price
for gas sold under this contract is a regional market index determined
monthly based on spot prices plus $0.02 per MMBtu.
Other industrial customers purchase natural gas from MESA under short-
to intermediate-term contracts. These sales totaled approximately 3.5 Bcf
in 1995.
Prior to 1993, MESA's right to sell natural gas produced from the West
Panhandle field was based, in part, upon contractual requirements to serve
customers in Amarillo, Texas, and its environs. An amendment to the PAA in
1993 removed this restriction, and MESA now has the right to market its
production elsewhere. MESA believes that the right to market production
outside the Amarillo area will ensure that MESA receives competitive terms
for its West Panhandle field production. Through 1999, MESA's West
Panhandle field production is under contract to customers as described
above.
NGL, Helium and LNG Sales
-------------------------
NGL production from both the Satanta and Fain plants are sold by
component pursuant to a seven-year contractual arrangement with Mapco Oil
and Gas Company, a major transporter and marketer of NGLs, at the greater of
Midcontinent or Gulf Coast prices at the time of sale. Helium is sold to an
industrial gas company under a fifteen-year agreement that provides for
annual price adjustments.
MESA has formed a liquefied natural gas ("LNG") production and
marketing joint venture, Mesa-Pacific LNG Joint Venture, L.L.C. ("Mesa
Pacific"), with Pacific Enterprises, the parent company of Southern
California Gas Company, in an effort to profit from the increasing use of
LNG as a transportation fuel. Mesa-Pacific purchases LNG from MESA and then
markets the product to fleet operators. MESA produces LNG at its Satanta
Plant and is reviewing plans to add LNG production capabilities at the Fain
Plant.
Major Customers
---------------
See Note 11 to the consolidated financial statements of the Company
located elsewhere in this Form 10-K for information on sales to major
customers.
Production Costs
- ----------------
The table below presents MESA's total production costs (lease operating
expenses and production and other taxes) by area of operation for each of
the years ended December 31 (in thousands, except per Mcf of natural gas
equivalent data):
1995 1994 1993
---------------- ---------------- ----------------
Total Per Mcfe Total Per Mcfe Total Per Mcfe
------- -------- ------- -------- ------- --------
Lease Operating Expense:
Hugoton............... $12,703 $ .18 $12,549 $ .17 $10,001 $ .18
West Panhandle........ 28,357 .73 28,347 .64 29,897 .66
Gulf Coast............ 9,848 .68 11,136 1.15 11,032 .99
Other................. 907 2.57 623 2.00 889 1.03
------- ------- -------
51,815 .42 52,655 .41 51,819 .45
------- ------- -------
Production and Other
Taxes:
Hugoton............... 15,004 .21 17,505 .24 15,405 .27
West Panhandle........ 3,216 .08 3,099 .07 4,581 .10
Gulf Coast............ 34 .00 68 .01 89 .01
Other................. 149 .42 634 2.04 257 .30
------- ------- -------
18,403 .15 21,306 .17 20,332 .18
------- ------- -------
Total Production Costs... $70,218 $ .57 $73,961 $ .58 $72,151 $ .63
======= ======= =======
MESA lease operating expenses consist of lease maintenance, gathering
and processing costs and have a significant fixed-cost component. As a
result, the production cost per Mcfe in the table above is affected by
changes in the volume of oil and gas produced. Production tax rates in
Kansas, where MESA's Hugoton field properties are located, are assessed on
wellhead value. These rates were reduced from 7% in 1993 to 6% in 1994 and
5% in 1995. In 1993 West Panhandle field taxes included a one-time
adjustment related to prior years' production.
See "-- Costs and Expenses" in "Management's Discussion and Analysis of
Financial Condition and Results of Operations" located elsewhere in this
Form 10-K.
Drilling Activities
- -------------------
The following table shows the results of MESA's drilling activities for
the last five years:
1995 1994 1993 1992 1991
----------- ----------- ----------- ----------- -----------
Gross Net Gross Net Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Exploratory
Wells:
Productive.... 1 .3 -- -- -- -- 5 4.1 6 4.7
Dry........... 4 4.0 -- -- 1 1.0 1 .4 1 .2
Development
Wells:
Productive.... 20 14.0 31 24.5 43 29.1 22 16.5 26 10.9
Dry........... -- -- 1 .8 -- -- -- -- -- --
----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Total....... 25 18.3 32 25.3 44 30.1 28 21.0 33 15.8
===== ===== ===== ===== ===== ===== ===== ===== ===== =====
At December 31, 1995, the Company was participating in the drilling of
one gross (.25 net) well.
Producing Acreage and Wells, Undeveloped Acreage
- ------------------------------------------------
MESA's ownership of oil and gas acreage held by production, producing
wells and undeveloped oil and gas acreage as of December 31, 1995, is set
forth in the following table:
Producing Producing Undeveloped
Acreage Wells Acreage
---------------- -------------- --------------
Gross Net Gross Net Gross Net
------- ------- ----- ------- ------ ------
Onshore U.S.:
Kansas................ 258,818 231,278 1,387 988.9 5,280 5,280
Texas................. 241,354 185,654 601 452.4 480 156
Wyoming............... 11,477 4,365 2 -- 14,926 9,391
North Dakota.......... 4,661 3,532 20 3.8 3,932 2,572
Other................. 2,597 2,139 13 1.3 22,012 11,573
------- ------- ----- ------- ------ ------
Total Onshore.... 518,907 426,968 2,023 1,446.4 46,630 28,972
------- ------- ----- ------- ------ ------
Offshore U.S.:
Louisiana............. 87,024 45,710 189 39.7 20,210 19,898
Texas................. 73,808 18,848 59 10.1 17,280 17,280
------- ------- ----- ------- ------ ------
Total Offshore... 160,832 64,558 248 49.8 37,490 37,178
------- ------- ----- ------- ------ ------
Grand Total................ 679,739 491,526 2,271 1,496.2 84,120 66,150
======= ======= ===== ======= ====== ======
MESA has interests in 2,092 gross (1,473.5 net) producing gas wells and
179 gross (22.7 net) producing oil wells in the United States. MESA also
owns approximately 84,632 net acres of producing minerals and 42,964 net
acres of nonproducing minerals in the United States.
The NGV Business
- ----------------
MESA believes that the transportation market offers opportunities to
realize premium prices for natural gas. MESA believes that the natural gas
vehicles ("NGV") market will develop and expand in the next decade,
particularly in light of (i) the National Energy Policy Act of 1992, (ii)
the amendments to the 1990 Federal Clean Air Act which require the use of
alternative fuels by certain fleets, (iii) the requirements of numerous
state and municipal environmental regulations, (iv) generally increased
awareness of the adverse environmental and pollution effects of crude
oil-based motor fuels, and (v) the development of more efficient equipment
to convert gasoline- and diesel-burning engines to operate on natural gas.
MESA's strategies have included (i) the development, manufacture, and sale
of engine-specific conversion equipment which meets the most stringent
emissions standards, and (ii) pursuing conversion equipment sales, fleet
conversions, fueling station installations, and the administration of
fueling and conversion programs. In 1996 MESA initiated a strategic process
designed to redirect its efforts in the natural gas-fuel systems business.
MESA expects to continue to be active in the development of conversion
systems and will begin providing contract engineering support for heavy-duty
natural gas engine applications, but will no longer market, manufacture or
install such systems.
Conversion Equipment
-------------------
MESA's wholly owned subsidiary, Mesa Environmental Ventures Co. ("Mesa
Environmental") has developed a natural gas vehicle conversion system, the
Gas Engine Management ("GEM") system, which MESA believes is the cleanest
and most advanced conversion product in the industry. Mesa Environmental is
currently marketing its GEM system to fleet operators in the United States.
In February 1996 Mesa Environmental signed letters of intent with two
companies to exchange certain of its assets and GEM technology, including
the right to manufacture and install GEM systems, for equity in one such
company and a royalty interest from the other. MESA believes that its
association with these leading manufacturers and marketers will ultimately
provide MESA greater profit potential in the natural gas vehicle conversion
business.
Fueling Business
----------------
In 1994 MESA entered into a fueling arrangement with a large operator
of airport shared-ride fleet vehicles. MESA agreed to finance the
acquisition by the fleet operator of certain natural gas-fueled vans and
conversion equipment, and the fleet operator agreed to purchase natural gas
at MESA's fueling facilities. This financing/fueling arrangement is
designed to be a model for similar agreements with fleet operators at select
other locations in the U.S. MESA currently operates natural gas fueling
stations near the Phoenix, Arizona, airport and in Anaheim, California.
MESA plans to open a new facility near LAX Airport in Los Angeles in 1996.
Organizational Structure
- ------------------------
MESA owns and operates its oil and gas properties and other assets
through various direct and indirect subsidiaries. Its direct wholly owned
subsidiaries are Mesa Operating Co. ("MOC"), Mesa Holding Co. ("MHC"), and
Hugoton Management Co. ("HMC"). Its principal indirect wholly owned
subsidiary is Hugoton Capital Limited Partnership ("HCLP").
MOC
---
MOC owns MESA's properties in the West Panhandle field of Texas and
MESA's interests in the Gulf of Mexico and the Rocky Mountain area. MOC
also owns an approximate 99% limited partnership interest in HCLP. In
addition, MOC owns helium attributable to its West Panhandle field
properties and HCLP's Hugoton field properties.
MOC is MESA's principal operating subsidiary. Most of MESA's employees
are employed by MOC, and MOC is generally responsible for all of MESA's
operations, administration, and marketing, including the operations of HCLP.
HCLP
----
Substantially all of MESA's Hugoton field property interests (including
gathering systems and compression and gas processing facilities), are owned
by HCLP. HCLP also owns the Satanta Plant, which was constructed by MOC.
MOC operates the plant under a long-term lease.
HCLP was formed in 1991 to own substantially all of MESA's Hugoton
field properties and to issue certain long-term notes secured by those
properties (the "HCLP Secured Notes"). The indenture and mortgage for the
HCLP Secured Notes contain various covenants which, among other things,
limit HCLP's ability to sell or acquire oil and gas property interests,
incur additional indebtedness, make unscheduled capital expenditures, make
distributions of property or funds subject to the mortgage, enter into
certain types of long-term contracts, or forward sales of production. The
agreements also require HCLP to remain in partnership form; its general
partner is HMC. The assets of HCLP, which is required to maintain separate
existence from MESA, are generally not available to pay creditors of MESA or
its subsidiaries other than HCLP. The HCLP agreements require proceeds from
production to be applied towards payment of HCLP's operating,
administrative, and capital costs, and to service HCLP's debt. To the
extent cash flows exceed these requirements, such "excess cash" is generally
available for distribution to MESA subsidiaries that own an equity interest
in HCLP.
MHC
---
MHC principally conducts various investment activities. At December
31, 1995, MHC held approximately $74 million of cash and investments, an
approximate 1% limited partnership interest in HCLP, and all of the equity
of Mesa Environmental.
History of MESA
- ---------------
In 1964 Original Mesa was formed as a public corporation engaged in the
business of exploring for and producing oil and natural gas. Original
Mesa's reserves and revenues grew significantly throughout the 1960s, 1970s,
and early 1980s as a result of successful exploration, development and
acquisitions. Original Mesa conducted operations in the United States, and
at various times, Canada, the North Sea, and Australia. Original Mesa was
reorganized as the Partnership, a publicly traded limited partnership, in
1985 and the Partnership was converted to corporate form as MESA Inc. in
1991.
MESA's two most recent significant acquisitions, Pioneer Corporation in
1986 (which included MESA's West Panhandle field) and Tenneco Inc.'s
midcontinent division in 1988 (which included approximately one-fourth of
MESA's current Hugoton holdings), increased reserves from 1.4 Tcfe at year-
end 1985 to over 2.8 Tcfe at year-end 1988. MESA incurred significant debt
to make the reserve acquisitions. MESA also made cash distributions to
Partnership unitholders of over $1.1 billion from 1986 through 1990. The
increased debt associated with the acquisitions, the distributions, and
declining gas prices through the late 1980s and early 1990s, significantly
impaired MESA's financial strength and flexibility. As a result, in 1991
MESA began to sell assets and refinance and restructure its debt. From 1989
through 1993, MESA sold nearly 600 Bcfe of proved producing reserves for an
aggregate of over $633 million. MESA used the proceeds principally to
reduce debt. MESA refinanced $550 million of bank debt in 1991 with the
formation of HCLP and the issuance of the HCLP Secured Notes. In 1993 MESA
restructured substantially all of its $600 million of outstanding
subordinated debt in a debt exchange transaction, which had the effect of
deferring over $150 million of cash interest requirements until after 1995.
In the second quarter of 1994 MESA completed a public offering of
approximately 16.3 million shares of common stock at a public offering price
of $6.00 per share (the "Equity Offering"). The Equity Offering resulted in
net proceeds to MESA of approximately $93 million which were used to repay
debt.
In an effort to address its liquidity issues, MESA's Board approved a
proposal solicitation process which started in late 1994 and was expanded in
mid-1995. The process has included solicitation of proposals for a sale of
MESA, a stock-for-stock merger, joint ventures, asset sales, equity
infusions, and refinancing transactions. On February 28, 1996, MESA entered
into a letter of intent with Rainwater to raise $265 million of equity in
connection with a refinancing of MESA's debt.
For additional information regarding the Rainwater transaction and
MESA's financial position, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations" located elsewhere in this
Form 10-K.
Competition
- -----------
The oil and gas business is highly competitive in the search for,
acquisition of, and sale of, oil and gas. MESA's competitors in these
endeavors include the major oil and gas companies, independent oil and gas
concerns, and individual producers and operators, as well as major pipeline
companies, many of which have financial resources greatly in excess of those
of MESA. MESA believes that its competitive position is affected by, among
other things, price, contract terms, and quality of service.
MESA is one of the largest owners of natural gas reserves in the United
States. Production from MESA's properties has access to a substantial
portion of the major metropolitan markets in the United States through
numerous pipelines and other purchasers. MESA is not dependent upon any
single purchaser or small group of purchasers.
MESA believes that its competitive position is enhanced by its
substantial long-life reserve holdings and related deliverability, its
flexibility to sell such reserves in a diverse number of markets, and its
ability to produce its reserves at a low cost.
Operating Hazards and Uninsured Risks
- -------------------------------------
MESA's oil and gas activities are subject to all of the risks normally
incident to exploration for and production of oil and gas, including
blowouts, cratering, and fires, each of which could result in damage to life
and property. Offshore operations are subject to a variety of operating
risks, such as hurricanes and other adverse weather conditions, and lack of
access to existing pipelines or other means of transporting production.
Furthermore, offshore oil and gas operations are subject to extensive
governmental regulations, including certain regulations that may, in certain
circumstances, impose absolute liability for pollution damages, and to
interruption or termination by governmental authorities based on
environmental or other considerations. In accordance with customary
industry practices, MESA carries insurance against some, but not all, of
these risks. Losses and liabilities resulting from such events would reduce
revenues and increase costs to MESA to the extent not covered by insurance.
Regulation and Prices
- ---------------------
MESA's operations are affected from time to time in varying degrees by
political developments and federal, state, and local laws and regulations.
In particular, oil and gas production operations and economics are, or in
the past have been, affected by price controls, taxes, conservation, safety,
environmental, and other laws relating to the petroleum industry, by changes
in such laws and by constantly changing administrative regulations.
Price Regulations
-----------------
In the recent past, maximum selling prices for certain categories of
oil, gas, condensate, and NGLs were subject to federal regulation. In 1981
all federal price controls over sales of crude oil, condensate and NGLs were
lifted. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act
(the "Decontrol Act") deregulated natural gas prices for all "first sales"
of natural gas, which includes all sales by MESA of its own production. As
a result, all sales of MESA's domestically produced oil, gas, condensate and
NGLs may be sold at market prices, unless otherwise committed by contract.
Natural Gas Regulation
----------------------
Historically, interstate pipeline companies generally acted as
wholesale merchants by purchasing natural gas from producers and reselling
the gas to local distribution companies and large end-users. Commencing in
late 1985, the FERC issued a series of orders that have had a major impact
on interstate natural gas pipeline operations, services, and rates, and thus
have significantly altered the marketing and price of natural gas. The
FERC's key rulemaking action, Order 636 ("Order 636"), issued in April 1992,
required each interstate pipeline to, among other things, "unbundle" its
traditional bundled sales services and create and make available on an open
and nondiscriminatory basis numerous constituent services (such as gathering
services, storage services, firm and interruptible transportation services,
and stand-by sales and gas balancing services), and to adopt a new rate-
making methodology to determine appropriate rates for those services. To
the extent the pipeline company or its sales affiliate makes gas sales as a
merchant in the future, it does so pursuant to private contracts in direct
competition with all other sellers, such as MESA; however, pipeline
companies and their affiliates were not required to remain "merchants" of
gas, and most of the interstate pipeline companies have become "transporters
only." In subsequent orders, the FERC largely affirmed the major features
of Order 636 and denied a stay of the implementation of the new rules
pending judicial review. By the end of 1994, the FERC had concluded the
Order 636 restructuring proceedings, and, in general, accepted rate filings
implementing Order 636 on every major interstate pipeline. However, even
through the implementation of Order No. 636 on individual interstate
pipelines is essentially complete, many of the individual pipeline
restructuring proceedings, as well as Order No. 636 itself and the
regulations promulgated thereunder, are subject to pending appellate review
and could possibly be changed as a result of future court orders. MESA
cannot predict whether the FERC's orders will be affirmed on appeal or what
the effects will be on its business.
In recent years the FERC also has pursued a number of other important
policy initiatives which could significantly affect the marketing of natural
gas. Some of the more notable of these regulatory initiatives include (i) a
series of orders in individual pipeline proceedings articulating a policy of
generally approving the voluntary divestiture of interstate pipeline-owned
gathering facilities by interstate pipelines to their affiliates (the so-
called "spin-down" of previously-regulated gathering facilities to the
pipeline's nonregulated affiliate), (ii) the completion of a rulemaking
involving the regulation of pipelines with marketing affiliates under Order
No. 497, (iii) the FERC's on-going efforts to promulgate standards for
pipeline electronic bulletin boards and electronic data exchange, (iv) a
generic inquiry into the pricing of interstate pipeline capacity, (v)
efforts to refine the FERC's regulations controlling operation of the
secondary market for released pipeline capacity, and (vi) a policy statement
regarding market-based rates and other non-cost-based rates for interstate
pipeline transmission and storage capacity. Several of these initiatives
are intended to enhance competition in natural gas markets, although some,
such as "spin-downs," may have the adverse effect of increasing the cost of
doing business on some in the industry as a result of the monopolization of
those facilities by their new, unregulated owners. The FERC has attempted
to address some of these concerns in its orders authorizing such "spin-
downs," but it remains to be seen what effect these activities will have on
access to markets and the cost to do business. As to all of these recent
FERC initiatives, the on-going, or, in some instances, preliminary evolving
nature of these regulatory initiatives makes it impossible at this time to
predict their ultimate impact on MESA's business.
MESA owns, directly or indirectly, certain natural gas facilities that
it believes meet the traditional tests the FERC has used to establish a
company's status as a gatherer not subject to FERC jurisdiction under the
Natural Gas Act of 1938 (the "NGA"). Moreover, recent orders of the FERC
have been more liberal in their reliance upon or use of the traditional
tests, such that in many instances, what was once classified as
"transmission" may now be classified as "gathering." MESA transports its
own gas through these facilities. MESA also transports certain of its gas
through gathering facilities owned by others, including interstate
pipelines. With respect to item (i) in the preceding paragraph, on May 27,
1994, the FERC issued orders in the context of the "spin-off" or "spin-down"
of interstate pipeline-owned gathering facilities. A "spin-off" is a FERC-
approved sale of such facilities to a non-affiliate. A "spin-down" is the
transfer by the interstate pipeline of its gathering facilities to an
affiliate. A number of spin-offs and spin-downs have been approved by the
FERC and implemented. The FERC held that it retains jurisdiction over
gathering provided by interstate pipelines, but that it generally does not
have jurisdiction over pipeline gathering affiliates, except in the event of
affiliate abuse (such as actions by the affiliate undermining open and
nondiscriminatory access to the interstate pipeline). These orders require
nondiscriminatory access for all sources of supply, prohibit the tying of
pipeline transportation service to any service provided by the pipeline's
gathering affiliate, and require the new gathering company to submit a
"default" contract if a satisfactory contract cannot be mutually agreed upon
by the interstate pipeline and its existing customers. Several petitions
for rehearing of the FERC's May 27, 1994, orders were filed. On November
30, 1994, the FERC issued a series of rehearing orders largely affirming the
May 27, 1994, orders. The FERC clarified that "default" contracts are
intended to serve only as a transition mechanism to prevent arbitrary
termination of gathering service to existing customers. Also, the FERC now
requires interstate pipelines to not only seek authority under Section 7(b)
of the NGA to abandon certificated facilities, but also to seek authority
under Section 4 of the NGA to terminate service from both certificated and
uncertificated facilities. On December 31, 1994, an appeal was filed with
the U.S. Court of Appeals for the D.C. Circuit to overturn three of the
FERC's November 30, 1994, orders. MESA cannot predict what the ultimate
effect of the FERC's orders pertaining to gathering will have on its
production and marketing, or whether the Appellate Court will affirm the
FERC's orders on these matters.
State and Other Regulation
--------------------------
All of the jurisdictions in which MESA owns producing oil and gas
properties have statutory provisions regulating the exploration for and
production of crude oil and natural gas. Such regulation includes requiring
permits for the drilling of wells, maintaining bonding requirements in order
to drill or operate wells, and relating to the location of wells, the method
of drilling and casing wells, the surface use and restoration of properties
upon which wells are drilled and the plugging and abandoning of wells.
MESA's operations are also subject to various conservation laws and
regulations. These include the regulation of the size of drilling and
spacing units or proration units and the density of wells which may be
drilled and the unitization or pooling of oil and gas properties. In this
regard, some states allow the forced pooling or integration of tracts to
facilitate exploration while other states rely on voluntary pooling of lands
and leases. In addition, state conservation laws establish maximum rates of
production from oil and natural gas wells, generally prohibit the venting or
flaring of natural gas and impose certain requirements regarding the
ratability of production. Some states, such as Texas, Oklahoma, and Kansas
have, in recent years, reviewed and substantially revised methods previously
used to make monthly determinations of allowable rates of production from
fields and individual wells. See "-- Production" for a discussion of recent
changes to MESA's allowables in the Hugoton field. The effect of these
regulations is to limit the amounts of oil and natural gas MESA can produce
from its wells, and to limit the number of wells or the location at which
MESA can drill.
State regulation of gathering facilities generally includes various
safety, environmental, and in some circumstances, non-discriminatory take
requirements, but does not generally entail rate regulation. Natural gas
gathering has received greater regulatory scrutiny at both the state and
federal levels in the wake of the interstate pipeline restructuring under
Order 636. For example, Oklahoma recently enacted a prohibition against
discriminatory gathering rates, and certain Texas and Kansas regulatory
officials have expressed interest in evaluating similar rules in their
respective states.
Federal Royalty Matters
-----------------------
By a letter dated May 3, 1993, directed to thousands of producers
holding interests in federal leases, the United States Department of the
Interior (the "DOI") announced its interpretation of existing federal leases
to require the payment of royalties on past natural gas contract settlements
which were entered into in the 1980s and 1990s to resolve, among other
things, take-or-pay and minimum take claims by producers against pipelines
and other buyers. The DOI's letter set forth various theories of liability,
all founded on the DOI's interpretation of the term "gross proceeds" as used
in federal leases and pertinent federal regulations. In an effort to
ascertain the amount of such potential royalties, the DOI sent a letter to
producers on June 18, 1993, requiring producers to provide all data on all
natural gas contract settlements, regardless of whether gas produced from
federal leases was involved in the settlement. MESA received a copy of this
information demand letter. In response to the DOI's action, in July 1993
various industry associations and others filed suit in the United States
District Court for the Northern District of West Virginia seeking an
injunction to prevent the collection of royalties on natural gas contract
settlement amounts under the DOI's theories. The lawsuit, styled
"Independent Petroleum Association v. Babbitt," was transferred to the
United States District Court in Washington, D.C. On June 14, 1995, the
Court issued a ruling in this case holding that royalties are payable to the
United States on gas contract settlement proceeds in accordance with the
Minerals Management Service's May 3, 1993, letter to producers. This ruling
was appealed and is now pending in the D.C. Circuit Court of Appeals. The
DOI's claim in a bankruptcy proceeding against a producer based upon an
interstate pipeline's earlier buy-out of the producer's gas sale contract
was rejected by the Federal Bankruptcy Court in Lexington, Kentucky, in a
proceeding styled "Century Offshore Management Corp.". While the facts of
the Court's decision do not involve all of the DOI's theories, the Court
found on those at issue that DOI's theories were without legal merit, and
the Court's reasoning suggests that the DOI's other claims are similarly
deficient. This decision was upheld in the District Court and is now on
appeal in the Sixth Circuit Court of Appeals. Because both the "Independent
Petroleum Association v. Babbitt" and "Century Offshore Management Corp."
decisions have been appealed, and because of the complex nature of the
calculations necessary to determine potential additional royalty liability
under the DOI's theories, it is impossible to predict what, if any,
additional or different royalty obligation the DOI may assert or ultimately
be entitled to recover with respect to any of MESA's prior natural gas
contract settlements.
Environmental Matters
---------------------
MESA's operations are subject to numerous federal, state, and local
laws and regulations controlling the discharge of materials into the
environment or otherwise relating to the protection of the environment,
including the Comprehensive Environmental Response, Compensation, and
Liability Act ("CERCLA"), also known as the "Federal Superfund Law." Such
laws and regulations, among other things, impose absolute liability upon the
lessee under a lease for the cost of clean-up of pollution resulting from a
lessee's operations, subject the lessee to liability for pollution damages,
may require suspension or cessation of operations in affected areas, and
impose restrictions on the injection of liquids into subsurface aquifers
that may contaminate groundwater. MESA maintains insurance against costs
of clean-up operations, but it is not fully insured against all such risks.
A serious incident of pollution may, as it has in the past, also result in
the DOI requiring lessees under federal leases to suspend or cease operation
in the affected area. In addition, the recent trend toward stricter
standards in environmental legislation and regulation may continue. For
instance, legislation has been proposed in Congress from time to time that
would reclassify certain oil and gas production wastes as "hazardous wastes"
which would make the reclassified exploration and production wastes subject
to much more stringent handling, disposal, and clean-up requirements. If
such legislation were to be enacted, it could have a significant impact on
MESA's operating costs, as well as the oil and gas industry in general.
State initiatives to further regulate the disposal of oil and gas wastes are
also pending in certain states, and these various initiatives could have a
similar impact on MESA.
The Oil Pollution Act of 1990 ("OPA") and regulations thereunder impose
a variety of regulations on "responsible parties" (which include owners and
operators of offshore facilities) related to the prevention of oil spills
and liability for damages resulting from such spills in United States
waters. In addition, OPA imposes ongoing requirements on responsible
parties, including proof of financial responsibility to cover at least some
costs in a potential spill. On August 25, 1993, the Minerals Management
Service (the "MMS") published an advance notice of its intention to adopt a
rule under OPA that would require owners and operators of offshore oil and
gas facilities to establish $150 million in financial responsibility. Under
the proposed rule, financial responsibility could be established through
insurance, guaranty, indemnity, surety bond, letter of credit, qualification
as a self-insurer, or a combination thereof. There is substantial
uncertainty as to whether insurance companies or underwriters will be
willing to provide coverage under OPA because the statute provides for
direct lawsuits against insurers who provide financial responsibility
coverage, and most insurers have strongly protested this requirement. The
financial tests or other criteria that will be used to judge self-insurance
are also uncertain. As a result of the strong opposition to the $150
million financial responsibility requirement in its present form, the DOI
has decided not to implement the OPA until some time in 1996. While there
has been discussion in the United States Congress about amending the
financial responsibility requirements of the OPA, such action has not been
undertaken to date. MESA cannot predict the final form of the financial
responsibility rule that will be adopted by the MMS, but such rule has the
potential to result in the imposition of substantial additional annual costs
on MESA or otherwise have material adverse effects on MESA's operations in
the Gulf of Mexico.
Under current federal regulations concerning offshore operations, the
MMS is authorized to require lessees to post supplemental bonds to cover
their potential leasehold abandonment costs. By letter dated November 9,
1995, MESA was advised by the MMS that it does not qualify for a waiver from
supplemental bond requirements and that MESA may be required to post
supplemental bonds covering its potential obligations with respect to
offshore operations. On December 8, 1995, the MMS published a Notice of
Proposed Rulemaking in which the MMS proposed to further clarify and update
its Outer Continental Shelf operational bond requirements. Comments with
respect to this proposed rulemaking are due March 7, 1996. MESA cannot
predict the final form of the financial responsibility rule that will be
adopted by the MMS or whether the MMS will require it to post supplemental
bonds, but such rule or requirement has the potential to result in
substantial additional annual costs to MESA or otherwise have material
adverse effects on MESA's operation in the Gulf of Mexico.
In 1993 a number of companies in New Mexico, including MESA, were named
in a preliminary information request from the Environmental Protection
Agency (the "EPA") as persons who may be potentially responsible for costs
incurred in connection with the Lee Acres Landfill site. Although MESA did
not directly dispose of any materials at the site, it may have contracted to
transport materials from its operations with certain trucking companies also
named in the information request. To the extent any materials produced by
MESA may have been transported to the site, MESA believes that such
materials were rainwater and/or water produced from natural gas wells, which
MESA believes are exempt or excluded from the definitions of "hazardous
waste" or "hazardous substance" under applicable Federal environmental laws,
although the EPA may assert a contrary position. Since submitting its
response to the information request in April 1994, MESA has not received any
additional inquiries or information from the EPA concerning the site,
including whether MESA is, in fact, asserted to be a responsible party for
the site or what potential liability, if any, MESA may face in connection
with this matter.
MESA is not involved in any other administrative or judicial
proceedings arising under federal, state, or local environmental protection
laws and regulations which would have a material adverse effect on MESA's
financial position or results of operations.
Item 2. Properties
===================
Reference is made to Item 1 of this Form 10-K for a description of
MESA's properties.
Item 3. Legal Proceedings
==========================
Masterson Lawsuit
- -----------------
In February 1992 the current lessors of an oil and gas lease (the "Gas
Lease") dated April 30, 1955, between R. B. Masterson, et al., as lessor,
and CIG, as lessee, sued CIG in Federal District Court in Amarillo, Texas,
claiming that CIG had underpaid royalties due under the Gas Lease. The
Company owns an interest in the Gas Lease. In August 1992 CIG filed a
third-party complaint against the Company for any such royalty underpayments
which may be allocable to the Company's interest in the Gas Lease. The
plaintiffs alleged that the underpayment was the result of CIG's use of an
improper gas sales price upon which to calculate royalties and that the
proper price should have been determined pursuant to a "favored-nations"
clause in a July 1, 1967, amendment to the Gas Lease (the "Gas Lease
Amendment"). The plaintiffs also sought a declaration by the court as to
the proper price to be used for calculating future royalties.
The plaintiffs alleged royalty underpayments of approximately $500
million (including interest at 10%) covering the period from July 1, 1967,
to the present. In March 1995 the court made certain pretrial rulings that
eliminated approximately $400 million of the plaintiffs' claims (which
related to periods prior to October 1, 1989), but which also reduced a
number of the Company's defenses. The Company and CIG filed stipulations
with the court whereby the Company would have been liable for between 50%
and 60%, depending on the time period covered, of an adverse judgment
against CIG for post-February 1988 underpayments of royalties. On March 22,
1995, a jury trial began and on May 4, 1995, the jury returned its verdict.
Among its findings, the jury determined that CIG had underpaid royalties for
the period after September 30, 1989, in the amount of approximately
$140,000. Although the plaintiffs argued that the "favored-nations" clause
entitled them to be paid for all of their gas at the highest price
voluntarily paid by CIG to any other lessor, the jury determined that the
plaintiffs were estopped from claiming that the "favored-nations" clause
provides for other than a pricing-scheme to pricing-scheme comparison. In
light of this determination, and the plaintiffs' stipulation that a pricing-
scheme to pricing-scheme comparison would not result in any "trigger prices"
or damages, defendants asked the court for a judgment that plaintiffs take
nothing. The court, on June 7, 1995, entered final judgment that plaintiffs
recover no monetary damages. The Company cannot predict whether the
plaintiffs will appeal.
Preference Unitholders
- ----------------------
The Company was a defendant in certain purported class-action lawsuits
related to the December 31, 1991, conversion of the Partnership into the
Company filed in the U.S. District Court for the Northern District of Texas-
- -Dallas Division in the fall of 1991. The lawsuits were brought under
Section 14(a) of the Securities Exchange Act of 1934 and Rule 14a-9
thereunder, as well as state law, and alleged, inter alia, that (i) the
General Partner breached fiduciary duties to the holders of Preference Units
in structuring the conversion of the Partnership to corporate form and
allocating Common Stock and (ii) the related proxy statement contained
material misstatements and omissions. This lawsuit sought payment of
preferential distribution amounts on the Preference Units plus unspecified
damages, attorneys' fees and other relief. On January 17, 1992, plaintiffs
moved for leave to amend their compliant to allege that it was also brought
under Sections 11, 12(2) and 15 of the Securities Act of 1933 and Rule 10b-5
under the Exchange Act and to allege that the Partnership failed to obtain
an allegedly required vote of 90% of unitholders or, in lieu thereof, the
required opinion of independent counsel. On June 5, 1992, a class was
certified. On August 12, 1994, the Court granted defendants' Motion for
Summary Judgment and entered a judgment in favor of all defendants. The
plaintiffs appealed, and on June 19, 1995, the Fifth Circuit affirmed the
decision of the District Court. No application for rehearing or petition
for writ of certiorari was filed. Accordingly, the judgment in favor of the
Company is final and nonappealable.
Lease Termination
- -----------------
In 1991 the Company sold certain producing oil and gas properties to
Seagull Energy Company ("Seagull"). In 1994 two lawsuits were filed against
Seagull in the 100th District Court in Carson County, Texas, by certain land
and royalty owners claiming that certain of the oil and gas leases owned by
Seagull have terminated due to cessation in production and/or lack of
production in paying quantities occurring at various times from first
production through 1994. In the third quarter of 1995 Seagull filed third-
party complaints against the Company claiming breach of warranty and false
representation in connection with the sale of such properties to Seagull.
The Company believes it has several defenses to these lawsuits including a
two-year limitation on indemnification set forth in the purchase and sale
agreement.
Seagull filed a similar third-party complaint June 29, 1995, against
the Company covering a different lease in the 69th District Court in Moore
County, Texas. The Company believes it has similar defenses in this case.
The plaintiffs in the cases against Seagull are seeking to terminate
the leases. Seagull, in its complaint against the Company, is seeking
unspecified damages relating to any leases which are terminated.
Shareholder Litigation
- ----------------------
On July 3, 1995, Robert Strougo filed a class action and derivative
action in the District Court of Dallas County, Texas, 160th Judicial
District, against T. Boone Pickens, Paul W. Cain, John L. Cox, John S.
Herrington, Wales H. Madden, Jr., Fayez S. Sarofim, Robert L. Stillwell, and
J. R. Walsh, Jr. (the "Director Defendants"), each of whom is a present or
former director of MESA. The class action is purportedly brought on behalf
of a class of MESA shareholders and alleges, inter alia, that the Board
infringed upon the suffrage rights of the class and impaired the ability of
the class to receive tender offers by adoptions of the shareholder rights
plan. The lawsuit is also brought derivatively on behalf of MESA and
alleges, inter alia, that the Board breached fiduciary duties to MESA by
adopting the shareholder rights plan and by failing to consider the sale of
MESA. The lawsuit seeks unspecified damages, attorneys' fees, and
injunctive and other relief. Two other lawsuits filed by Herman Krangel,
Lilian Krangel, Jacquelyn A. Cady, and William A. Montagne, Jr., in the
District Court of Dallas County have been consolidated into this lawsuit.
The Court is presently considering a motion to dismiss the plaintiffs'
consolidated petition.
On July 18, 1995, Deborah M. Eigen and Adele Brody filed a purported
derivative lawsuit in the U.S. District Court for the Northern District of
Texas, Dallas Division, against the Director Defendants in their capacities
as members of the Board. This lawsuit is brought under state law and
alleges, inter alia, that the Board breached fiduciary duties to MESA by
adopting a shareholder rights plan and by failing to consider the sale of
MESA. The lawsuit is brought derivatively on behalf of MESA and seeks
unspecified damages, attorneys' fees, and other relief. On January 22,
1996, the Court denied the Director Defendants' motion to dismiss for
failure to state a claim.
Contingencies
- -------------
See Note 9 to the consolidated financial statements of the Company
included elsewhere in this Form 10-K for discussion of the above legal
proceedings and the estimated effect, if any, on MESA's results of
operations and financial position.
Item 4. Submission of Matters to a Vote of Security Holders
============================================================
None.
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters
======================================================================
The following table sets forth, for the periods indicated, the high and
low closing prices for MESA's common stock as reported by the New York Stock
Exchange:
Common Stock
--------------
High Low
------ ------
1995:
First Quarter........................................ $6-1/8 $4-5/8
Second Quarter....................................... 6-1/8 3-1/2
Third Quarter........................................ 5-1/2 3-7/8
Fourth Quarter....................................... 4-7/8 3
1994:
First Quarter........................................ $8-1/2 $5-5/8
Second Quarter....................................... 7 5-3/8
Third Quarter........................................ 5-7/8 5-1/8
Fourth Quarter....................................... 5-1/2 3-5/8
- ----------
* MESA's common stock trades on the New York Stock Exchange under the
symbol MXP. At December 31, 1995, there were 64,050,009 common shares
outstanding.
* MESA has not paid any dividends with respect to its common stock and does
not expect to pay dividends in the future unless and until there is a
material and sustained increase in natural gas prices and adequate
provision has been made for further reduction of debt. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" and Note 4 to the consolidated financial statements of the
Company included elsewhere in this Form 10-K for a discussion of
restrictions on the payment of dividends.
At March 6, 1996, there were 18,376 record holders of MESA's common
shares.
Item 6. Selected Financial Data
================================
The following table sets forth selected financial information of MESA
as of the dates or for the periods indicated. This table should be read in
conjunction with the consolidated financial statements of the Company and
related notes thereto included elsewhere in this Form 10-K.
As of or for the Years Ended December 31
----------------------------------------------------------
1995 1994 1993 1992 1991
---------- ---------- ---------- ---------- ----------
(in thousands, except per share data)
Revenues........ $ 234,959 $ 228,737 $ 222,204 $ 237,112 $ 249,546
========== ========== ========== ========== ==========
Operating income $ 47,965 $ 28,683 $ 22,012 $ 26,221 $ 34,128
========== ========== ========== ========== ==========
Net loss........ $ (57,568) $ (83,353) $(102,448) $ (89,232) $ (79,163)
========== ========== ========== ========== ==========
Net loss per
common share... $ (.90) $ (1.42) $ (2.61) $ (2.31) $ (2.05)
========== ========== ========== ========== ==========
Dividends per
common share... $ -- $ -- $ -- $ -- $ --
========== ========== ========== ========== ==========
Total assets.... $1,464,696 $1,483,959 $1,533,382 $1,676,523 $1,832,816
========== ========== ========== ========== ==========
Long-term debt,
including
current
maturities..... $1,236,743 $1,223,293 $1,241,294 $1,286,155 $1,310,705
========== ========== ========== ========== ==========
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
========================================================================
Disclosure Regarding Forward-Looking Statements
- -----------------------------------------------
This Form 10-K includes "forward-looking statements" within the meaning
of Section 27A of the Securities Act of 1933, as amended, and Section 21E of
the Securities Exchange Act of 1934, as amended. All statements other than
statements of historical facts included in this Form 10-K, including without
limitation, the statements under "Capital Resources and Liquidity" and
Notes 2 and 4 to the consolidated financial statements of the Company
regarding MESA's financial position, strategic alternatives, and financial
instrument covenant compliance, are forward-looking statements. Although
MESA believes that the expectations reflected in such forward-looking
statements are reasonable, it can give no assurance that such expectations
will prove to have been correct. Important factors that could cause actual
results to differ materially from MESA's expectations ("Cautionary
Statements") are disclosed in this Form 10-K, including without limitation
in conjunction with the forward-looking statements included in this Form 10-
K. All subsequent written and oral forward-looking statements attributable
to MESA or persons acting on its behalf are expressly qualified in their
entirety by the Cautionary Statements.
Results of Operations
- ---------------------
The following table presents a summary of the results of operations of
MESA for the years indicated:
Years Ended December 31
-------------------------------
1995 1994 1993
--------- --------- ---------
(in thousands)
Revenues.............................. $ 234,959 $ 228,737 $ 222,204
Operating and administrative costs.... (103,571) (107,767) (100,093)
Depreciation, depletion and
amortization........................ (83,423) (92,287) (100,099)
--------- --------- ---------
Operating income...................... 47,965 28,683 22,012
Interest expense, net of
interest income..................... (132,708) (131,300) (131,298)
Other................................. 27,175 19,264 6,838
--------- --------- ---------
Net loss.............................. $ (57,568) $ (83,353) $(102,448)
========= ========= =========
Revenues
--------
The table below presents, for the years indicated, the revenues,
production and average prices received from sales of natural gas, natural
gas liquids and oil and condensate.
Years Ended December 31
----------------------------
1995 1994 1993
-------- -------- --------
Revenues (in thousands):
Natural gas......................... $129,534 $139,580 $141,798
Natural gas liquids................. 75,321 72,771 61,427
Oil and condensate.................. 19,594 7,877 12,428
-------- -------- --------
Total.......................... $224,449 $220,228 $215,653
======== ======== ========
Natural Gas Production (MMcf):
Hugoton............................. 48,871 51,986 47,476
West Panhandle...................... 20,357 22,983 23,786
Gulf Coast.......................... 8,073 7,359 8,517
Other............................... 11 11 41
-------- -------- --------
Total.......................... 77,312 82,339 79,820
======== ======== ========
Natural Gas Liquids Production (MBbls):
Hugoton............................. 3,524 3,430 1,481
West Panhandle...................... 2,994 3,423 3,480
Gulf Coast.......................... 48 53 81
Other............................... 5 5 8
-------- -------- --------
Total.......................... 6,571 6,911 5,050
======== ======== ========
Oil and Condensate Production (MBbls):
Hugoton............................. -- -- 104
West Panhandle...................... 118 164 153
Gulf Coast.......................... 1,025 337 352
Other............................... 52 45 129
-------- -------- --------
Total.......................... 1,195 546 738
======== ======== ========
Year Ended December 31
----------------------
1995 1994 1993
------ ------ ------
Weighted average sales price:
Natural gas (per Mcf)
Hugoton............................... $ 1.32 $ 1.57 $ 1.78
West Panhandle........................ 1.83 1.80 1.72
Gulf Coast............................ 1.59 1.81 2.08
Other................................. .54 1.29 .85
------ ------ ------
Average*......................... $ 1.65 $ 1.67 $ 1.79
====== ====== ======
Natural gas liquids (per Bbl)
Hugoton............................... $10.76 $10.03 $12.35
West Panhandle........................ 12.33 11.06 12.04
Gulf Coast............................ 11.37 11.52 12.61
Other................................. 8.77 8.58 10.51
------ ------ ------
Average.......................... $11.48 $10.55 $12.14
====== ====== ======
Oil and condensate (per Bbl)
Hugoton............................... $ -- $ -- $18.21
West Panhandle........................ 14.13 13.38 15.04
Gulf Coast............................ 16.57 15.18 16.69
Other................................. 16.48 14.43 17.08
------ ------ ------
Average.......................... $16.32 $14.58 $16.63
====== ====== ======
* Includes the effects of hedging activities. See "Natural Gas Prices"
below.
The increase in total revenues from sales of natural gas, NGLs, and oil
and condensate from 1994 to 1995 is primarily attributable to increased oil
and condensate production in 1995, increased liquids prices in 1995 and
approximately $12.7 million of natural gas hedge gains recognized in 1995.
These factors offset the decrease in natural gas and natural gas liquids
production and the lower market prices for natural gas production in 1995.
The increase in revenues from 1993 to 1994 was primarily due to increased
natural gas and natural gas liquids production in 1994, partially offset by
the decrease in prices from 1993 to 1994.
Natural gas revenues decreased from 1993 to 1994 and from 1994 to 1995.
In 1995 production was lower in both the Hugoton and West Panhandle fields
due to timing and duration of equipment maintenance and weather-related
reduction in demand, respectively. Total natural gas production increased
from 1993 to 1994 primarily due to higher allowables in the Hugoton field
partially offset by slightly lower West Panhandle and Gulf Coast production.
Average natural gas prices were slightly lower in 1995 than in 1994. Prices
received for market price-based production was $.22 per Mcf (14%) lower in
1995. MESA's hedge gains increased the reported prices for such production
by $.20 per Mcf. The lower market prices were the result of the continuing
surplus of natural gas supply. Average natural gas prices received were 7%
lower in 1994 than in 1993 due to generally lower market prices. (See
"Natural Gas Prices" below.)
NGL revenues increased in 1995 compared to 1994. Hugoton field NGL
production was slightly higher despite lower natural gas production
reflecting improved yields from the Satanta Plant. West Panhandle field NGL
production decreased in 1995 in proportion to the lower natural gas
production. The lower production was offset by higher average prices in
1995 due to improved market conditions for NGLs. NGL production increased
from 1993 to 1994 as a result of increases in Hugoton field liquids
production. In the third quarter of 1993 the Satanta Plant in the Hugoton
field was completed. The plant, which is capable of processing up to 250
MMcf of natural gas per day, replaced MESA's older Ulysses natural gas
processing plant which could process up to 160 MMcf per day. The Satanta
Plant has the ability to extract a greater quantity of NGLs per Mcf of
natural gas, reject nitrogen and produce crude helium.
Oil and condensate revenues increased approximately 150% from 1994 to
1995. Gulf Coast production was up over 200% due to successful drilling in
late 1994. Average oil and condensate prices were also higher in 1995 by
$1.74 per Bbl. Prior to the resumption of drilling in the Gulf Coast in
1994, MESA's oil and condensate production had been on a decline.
West Panhandle production is governed by the terms of a contract with
CIG. See discussion below under "Production Allocation Agreement."
MESA's production from the Hugoton field is affected by the allowables
set for the entire field and by the portion of allowables allocated to
MESA's wells. See "Production -- Hugoton Field" in the business section of
this Form 10-K.
Natural Gas Prices
------------------
Substantially all of MESA's natural gas production is sold under short-
or long-term sales contracts. Approximately 80% of MESA's annual natural
gas sales, whether or not such sales are governed by a contract, are at
market prices. The following table shows MESA's natural gas production sold
under fixed price contracts and production sold at market prices:
Years Ended December 31
--------------------------
1995 1994 1993
------ ------ ------
Natural Gas Production (MMcf):
Sold under fixed price contracts.......... 15,212 13,935 19,467
Sold at market prices..................... 62,100 68,404 60,353
------ ------ ------
Total production..................... 77,312 82,339 79,820
====== ====== ======
Percent sold at market prices............. 80% 83% 76%
====== ====== ======
In addition to its fixed price contracts, MESA will, when circumstances
warrant, hedge the price received for its market-sensitive production
through natural gas futures contracts. The following table shows the
effects of MESA's fixed price contracts and hedging activities on its
natural gas prices:
Years Ended December 31
--------------------------
1995 1994 1993
------ ------ ------
Average Natural Gas Prices (per Mcf):
Fixed price contracts..................... $ 2.12 $ 2.16 $ 1.94
Market prices received.................... 1.33 1.55 1.75
Hedge gains (losses)...................... .20 .01 (.01)
------ ------ ------
Total market prices.................. 1.53 1.56 1.74
------ ------ ------
Total average prices...................... $ 1.65 $ 1.67 $ 1.79
====== ====== ======
Gains and losses from hedging activities are included in natural gas
revenues when the hedged production occurs. MESA recognized gains from
hedging activities of $12.7 million in 1995, $895,000 in 1994, and losses of
$324,000 in 1993.
Costs and Expenses
------------------
MESA's aggregate costs and expenses declined by approximately 7% from
1994 to 1995. Lease operating expenses declined marginally due to decreased
production. Production and other taxes decreased 14% from 1994 to 1995 due
to decreased production in the Hugoton and West Panhandle fields and lower
tax rates for Hugoton field production in 1995. See "Production Costs" in
the business section located elsewhere in this Form 10-K. Exploration
charges in 1995 were greater than in 1994 reflecting increased exploration
activities in the Gulf of Mexico and consist primarily of exploratory dry-
hole expense. General and administrative ("G&A") expenses were lower in
1995 than in 1994 primarily due to lower legal expenses and a reduction in
employee benefit expenses. Depreciation, depletion and amortization
("DD&A") expense, which is calculated quarterly on a unit-of-production
basis, was lower in 1995 than in 1994 primarily due to lower equivalent
production in 1995, oil and gas reserve increases in the Hugoton and West
Panhandle fields in the fourth quarters of 1994 and 1995, and additional
reserve discoveries in the Gulf Coast in 1994 and 1995. (See "Supplemental
Financial Data" in the notes to the consolidated financial statements of the
Company located elsewhere in this Form 10-K for discussion of oil and gas
reserves.)
MESA's aggregate costs and expenses declined marginally from 1993 to
1994. Lease operating expenses increased by 2% as a result of higher
operating costs associated with MESA's Satanta Plant and higher Hugoton
field production. See "Production Costs" in the business section located
elsewhere in this Form 10-K. Exploration charges in 1994 were greater than
in 1993 reflecting MESA's increased exploration activities in the Gulf of
Mexico and resulted primarily from the purchase of 3-D seismic data. G&A
expenses were higher in 1994 than in 1993 primarily due to litigation
expenses associated with MESA's defense of a royalty lawsuit in the West
Panhandle field. DD&A expense was lower in 1994 compared to 1993. DD&A
expense reflects the 1994 reserve increases in the Hugoton and West
Panhandle fields and reserve discoveries in the Gulf Coast. (See
"Supplemental Financial Data" in the notes to the consolidated financial
statements of the Company located elsewhere in this Form 10-K.)
Other Income (Expense)
----------------------
Interest expense in 1995 was not materially different from 1994 and
1993 as average aggregate debt outstanding did not materially change.
Interest income increased from $10.7 million in 1993, to $13.5 million
in 1994, and to $15.9 million in 1995 as a result of higher average cash
balances and higher average interest rates earned on these cash balances in
1994 and 1995.
Results of operations for the years 1995, 1994, and 1993 include
certain items which are either non-recurring or are not directly associated
with MESA's oil and gas producing operations. The following table sets
forth the amounts of such items (in thousands):
Years Ended December 31
-------------------------
1995 1994 1993
------- ------- -------
Gains from investments...................... $18,420 $ 6,698 $ 3,954
Gains from collections from Bicoastal
Corporation............................... 6,352 16,577 18,450
Gains on dispositions of oil
and gas properties........................ -- -- 9,600
Litigation settlement....................... -- -- (42,750)
Gain from adjustment of contingency reserve. -- -- 24,000
Expense of debt exchange transaction........ -- -- (9,651)
Other....................................... 2,403 (4,011) 3,235
------- ------- -------
Total Other Income..................... $27,175 $19,264 $ 6,838
======= ======= =======
The gains from investments relate to MESA's investments in marketable
securities and energy futures contracts, which include New York Mercantile
Exchange ("NYMEX") futures contracts, commodity price swaps and options that
are not accounted for as hedges of future production. MESA's investments in
marketable securities and futures contracts are valued at market prices at
each reporting date with gains and losses included in the statement of
operations for such reporting period whether or not such gains or losses
have been realized. At December 31, 1995, MESA had recognized but not
realized approximately $7.6 million of gains primarily associated with open
positions in natural gas futures contracts. As of March 6, 1996, MESA had
closed substantially all of the positions open at December 31, 1995, at a
realized loss of $156,000. Positions which were open at December 31, 1995,
and remain open had unrealized gains of $1.7 million at March 6, 1996.
The gains from collection of interest from Bicoastal Corporation relate
to a note receivable from such company, which was in bankruptcy. MESA's
claims in the bankruptcy exceeded its recorded receivable. As of year-end
1995, MESA had collected the full amount of its allowed claim plus a portion
of the interest due on such claims. The gains on dispositions of oil and
gas properties relate primarily to 1993 sales of oil producing properties in
the deep Hugoton and Rocky Mountain areas for approximately $26 million.
The litigation settlement charge relates to MESA's 1994 settlement of a
lawsuit with Unocal Corporation ("Unocal"). The litigation related to a
1985 investment in Unocal by Original Mesa and certain other defendants.
The plaintiffs had sought to recover alleged "short-swing profits" plus
interest totaling over $150 million pursuant to Section 16(b) of the
Securities Exchange Act of 1934. In early 1994 MESA and the other
defendants reached a settlement with the plaintiffs and agreed to pay $47.5
million to Unocal, of which MESA's share was $42.8 million. MESA issued
additional 12-3/4% secured discount notes due June 30, 1998 with a face
amount of $48.2 million to fund its share of the settlement.
In the fourth quarter of 1993, MESA completed a settlement with the
Internal Revenue Service (the "IRS") resolving all tax issues relating to
the 1984 through 1987 tax returns of Original Mesa. MESA had previously
established contingency reserves for the IRS claims and certain other
contingent liabilities in excess of the actual and estimated liabilities.
As a result of the settlement with the IRS and the resolution and
revaluation of certain other contingent liabilities, MESA recorded a net
gain of $24 million in the fourth quarter of 1993.
The debt exchange expense relates to costs associated with MESA's $600
million debt exchange transaction completed in 1993.
Production Allocation Agreement
-------------------------------
Effective January 1, 1991, MESA entered into the PAA with CIG which
allocates 77% of reserves and production from the West Panhandle field to
MESA and 23% to CIG. During 1995, 1994, and 1993, MESA produced and sold
71%, 69%, and 74%, respectively, of total production from the field; the
balance of field production was sold by CIG. MESA records its 77% ownership
interest in natural gas production as revenue. The difference between the
net value of production sold by MESA and the net value of its 77%
entitlement is accrued as a gas balancing receivable. The revenues and
costs associated with such accrued production are included in results of
operations.
The following table presents the incremental effect on production and
results of operations from entitlement production recorded in excess of
actual sales as a result of the PAA (dollars in thousands):
Years Ended December 31
--------------------------- January 1, 1991
1995 1994 1993 To Date
------- ------- ------- ---------------
Revenues accrued........... $ 4,260 $ 8,662 $ 5,145 $58,715
Costs and expenses accrued. (1,576) (3,075) (1,059) (16,145)
------- ------- ------- -------
Recorded to receivable..... 2,684 5,587 4,086 42,570
------- ------- ------- -------
Depreciation, depletion
and amortization......... (1,680) (3,713) (1,244) (25,142)
------- ------- ------- -------
Total................. $ 1,004 $ 1,874 $ 2,842 $17,428
======= ======= ======= =======
Production Accrued:
Natural gas (MMcf).... 1,155 2,386 740 15,887
Natural gas liquids
(MBbls)............. 171 355 106 2,275
At December 31, 1995, the long-term gas balancing receivable from CIG,
net of accrued costs, relating to the PAA was $42.6 million, which is
included in other assets in the consolidated balance sheet. The provisions
of the PAA allow for periodic and ultimate cash balancing to occur. The PAA
also provides that CIG may not take in excess of its 23% share of ultimate
production.
Capital Resources and Liquidity
- -------------------------------
MESA is primarily in the business of exploring for, developing,
producing, processing and selling natural gas and oil. MESA owns and
operates its oil and gas properties and other assets through its direct and
indirect subsidiaries which include MOC, MHC and HCLP.
At December 31, 1995, MESA owned almost 1.9 trillion cubic feet of
estimated proved equivalent natural gas reserves. MESA's reserves are
located in the Hugoton field of southwest Kansas (64%), the West Panhandle
field of Texas (32%), the Gulf Coast (3%), and the Rocky Mountains (1%).
MOC owns all of MESA's interest in the West Panhandle field, the Gulf Coast
and the Rocky Mountains. HCLP owns substantially all of MESA's Hugoton
field interests with MOC holding the remaining portion of such interests.
MHC owns no oil and gas property interests, but does have a substantial
amount of cash and investments.
MESA is highly leveraged with over $1.2 billion of long-term debt,
including current maturities. HCLP is the obligor on approximately $505
million (41%) of MESA's debt which is secured by HCLP's Hugoton property
interests. The obligors on the remainder of MESA's debt are the Company and
MOC; the majority of such debt is secured by liens on the West Panhandle
field properties and a portion of MOC's equity interest in HCLP.
The assets and cash flows of HCLP that are subject to the mortgage
securing HCLP's debt are dedicated to service HCLP's debt and are not
available to pay creditors of MESA or its subsidiaries other than HCLP.
The debt of MOC and the Company, more fully described below, consists
primarily of bank debt and secured and unsecured discount notes (the
"Discount Notes"). MESA's current financial forecasts indicate, assuming no
changes in its capital structure and no significant transactions are
completed, that cash generated by operating activities, together with cash
and investments on hand, will not be sufficient for MOC and the Company to
make all of the debt principal and interest obligations due in June 1996.
In addition, certain covenants related to MESA's bank debt and certain
cross-default provisions of the Discount Notes could result in the
acceleration of approximately $656 million of long-term debt principal due
in mid-1997 and mid-1998 to the first half of 1996.
In an effort to address its liquidity issues, the Board approved and
implemented a proposal solicitation process which started in late 1994 and
was expanded in mid-1995. The process has included solicitation of
proposals for a sale of MESA, a stock-for-stock merger, joint ventures,
asset sales, equity infusions, and refinancing transactions. On February
28, 1996, MESA signed a letter of intent with Rainwater to raise $265
million of equity in connection with a refinancing of MESA's debt.
Set forth below and in Notes 2 and 4 to the consolidated financial
statements of the Company, is a more detailed discussion of MESA's debt, its
capital resources and liquidity, the Rainwater transaction, and the other
alternatives MESA may pursue to address its liquidity issues.
Long-term Debt
--------------
The following table provides additional information as to MESA's long-
term debt at December 31, 1995 (in thousands):
Obligors
------------------
MOC HCLP Total
-------- -------- ----------
Debt:
HCLP Secured Notes(a)............ $ -- $504,674 $ 504,674
Credit Agreement(b).............. 61,131 -- 61,131
12-3/4% secured discount
notes(c)(e).................... 618,518 -- 618,518
12-3/4% unsecured discount
notes(d)(e)..................... 39,725 -- 39,725
Other............................. 12,695 -- 12,695
-------- -------- ----------
732,069 504,674 1,236,743
Current maturities..................... (67,530) (33,883) (101,413)
-------- -------- ----------
Long-term debt......................... $664,539 $470,791 $1,135,330
======== ======== ==========
- ----------
(a) These notes are secured by the Hugoton field properties and are
due in semiannual installments through August 2012, but may be
repaid earlier depending on the rate of production from the
properties.
(b) The bank credit facility (the "Credit Agreement") is secured by a
first lien on MOC's West Panhandle field properties, MESA's equity
interest in MOC and a 76% limited partnership interest in HCLP
and is due in various installments through June 1997. At
December 31, 1995, the Credit Agreement also supported letters
of credit totaling $11.4 million that are not included in the
table above.
(c) These notes are due in June 1998 and are secured by second liens
on MOC's West Panhandle field properties and a 76% limited
partnership interest in HCLP.
(d) These notes are unsecured and are due on June 30, 1996.
(e) The Discount Notes began accruing interest, payable semiannually
beginning on December 31, 1995, at a rate of 12-3/4% per annum on
July 1, 1995.
The following tables summarize MESA's 1995 actual and 1996 through 1999
forecast cash requirements, assuming no changes in capital structure, for
interest, debt principal and capital expenditures (in thousands):
Actual Forecast
-------- -----------------------------------
1995 1996 1997 1998 1999
-------- -------- -------- -------- --------
HCLP:
Interest payments,
net(a)................$ 45,399 $ 46,700 $ 44,300 $ 41,700 $ 38,900
Principal repayments(b). 15,507 33,900 33,300 36,100 37,100
Capital expenditures(c). 9,682 4,000 900 200 200
-------- -------- -------- -------- --------
$ 70,588 $ 84,600 $ 78,500 $ 78,000 $ 76,200
======== ======== ======== ======== ========
MOC and the Company:
Interest payments,
net(a)................$ 3,427 $132,800 $ 97,300 $ 98,100 $ 84,700
Principal repayments:
Credit Agreement(d). 10,000 22,500 38,600 -- --
12-3/4% unsecured
discount notes(e). -- 39,700 -- -- --
12-3/4% secured
discount notes(e). -- -- -- 617,400 --
13-1/2%
subordinated
notes............. -- -- -- -- 7,400
Other............... -- 5,300 -- -- --
Capital expenditures(c). 32,615 24,000 14,500 500 --
-------- -------- -------- -------- --------
$ 46,042 $224,300 $150,400 $716,000 $ 92,100
======== ======== ======== ======== ========
- ----------
(a) Cash interest payments, net of interest income. The interest
payments due on December 31, 1995, related to the Discount Notes,
were made on January 2, 1996, in accordance with the terms of the
indentures and are reflected as 1996 cash outflows.
(b) HCLP Secured Note principal payments are determined based on
actual or deemed production from the HCLP Hugoton properties.
Such principal payment could be greater under certain
circumstances. See Note 4 to the consolidated financial
statements of the Company included elsewhere in this Form 10-K.
(c) Forecast capital expenditures represent MESA's best estimate of
drilling and facilities expenditures required to attain projected
levels of production from its existing properties during the
forecast period and to fund its current exploration and
development program. Capital expenditures in 1996 include $9.5
million of committed capital expenditures. Capital expenditures
may be greater than or less than the amounts reflected in the
table.
(d) Amounts due under the Credit Agreement may be accelerated if
tangible adjusted equity falls below $50 million. (See
discussion below.) Also, principal repayments set forth in the
table do not include the $11.4 million in letter of credit
obligations currently outstanding and required to be cash
collateralized when final maturities under the Credit Agreement
are repaid.
(e) Amounts due under the Discount Notes may be accelerated if there
is a continuing Event of Default under the Credit Agreement.
The Credit Agreement requires MESA to maintain tangible adjusted
equity, as defined, of $50 million, and available cash, as defined, of $32.5
million. At December 31, 1995, MESA's tangible adjusted equity was
approximately $64.7 million and available cash was $139.5 million.
Assuming no changes in its capital structure and no significant
transactions are completed, the Company expects to continue to report
substantial net losses and expects its tangible adjusted equity to fall
below $50 million in the first half of 1996. If and when MESA determines
that tangible adjusted equity is below $50 million, an Event of Default
would occur under the Credit Agreement and the bank would have the right to
accelerate the payment of all outstanding principal and require cash
collateralization of letters of credit. Unless and until the Credit
Agreement default were cured or waived or the debt under the Credit
Agreement were repaid or otherwise discharged, an Event of Default under the
Credit Agreement would cause a cross default under the Discount Note
indentures. Pursuant to the subordination provisions of such indentures,
MESA would be prohibited from making any payments on the Discount Notes for
specified periods upon and during the continuance of any Event of Default
under the Credit Agreement.
The Credit Agreement and the indentures governing the Discount Notes
restrict, among other things, MESA's ability to incur additional
indebtedness, create liens, pay dividends, acquire stock or make
investments, loans and advances.
Company Resources and Cash Flows
--------------------------------
The following table sets forth certain of MESA's near-term resources as
of or for the year ended December 31, 1995 (in thousands):
MOC HCLP MHC Total
------- ------- ---------- --------
Cash and investments(a)........ $65,441 $47,613 $74,369 $187,423
Working capital (deficit)...... (37,530) 3,393 77,938 43,801
Restricted cash(b)............. -- 57,731 -- 57,731
Cash flows from
operating activities:
Oil and gas sales, net
of production and
administrative costs..... $61,447 $63,810 $ -- $125,257
Interest payments, net(c). (7,988) (45,399) 4,561 (48,826)
Other..................... (2,702) 1,175 (5,663) (7,190)
------- ------- ------- --------
Net cash provided by
(used in) operating
activities............. $50,757 $19,586 $(1,102) $ 69,241
======= ======= ======= ========
- ----------
(a) Included in working capital. HCLP cash includes $40.2 million
which is subject to the HCLP Secured Note mortgage. On January 2,
1996, MOC made a $42 million interest payment on its Discount
Notes.
(b) Non-current asset in balance sheet. Represents a liquidity
reserve account established for the HCLP Secured Notes.
(c) Cash interest payments, net of interest income.
MESA's current financial forecasts indicate, assuming no changes in its
capital structure and no significant transactions are completed, that cash
generated by operating activities, together with available cash and
investment balances, will be not be sufficient to make all of its required
debt principal and interest obligations due in June 1996. If amounts
outstanding under the Credit Agreement were to be accelerated in the first
half of 1996, MESA would expect to have sufficient cash to meet the Credit
Agreement obligations and cure an Event of Default under the Credit
Agreement and avoid, at that time, cross defaults under the terms of its
Discount Note indentures. However, such a payment would substantially
deplete MESA's remaining cash and investments balances. MESA will make
decisions regarding such payments on its debt as they come due, taking into
account the status at that time of the Rainwater transaction discussed
below.
Exploration of Strategic Alternatives/
Proposed Transaction With Rainwater
--------------------------------------
In an effort to address its liquidity issues and to position MESA for
expansion through exploration and development, in December 1994 MESA
announced its intent to sell all or a portion of its interests in the
Hugoton field. In the first quarter of 1995 MESA began an auction process to
sell such properties. MESA's Board concluded the auction process in the
second quarter of 1995 after no acceptable bids were received for the
Hugoton properties.
On July 6, 1995, the Board approved and implemented a proposal
solicitation process which expanded its exploration of strategic
alternatives to include consideration of the sale of MESA, a stock-for-
stock merger, joint ventures, asset sales, equity infusions, and refinancing
transactions. MESA engaged an independent financial advisor to assist in
these efforts and to solicit proposals on its behalf. The proposal
solicitation process commenced in August 1995 and MESA received proposals
beginning on November 20, 1995.
On February 28, 1996, MESA signed a letter of intent with Rainwater to
raise $265 million of equity in connection with a refinancing of MESA's
debt. Pursuant to the terms of the letter of intent, Rainwater will
purchase in a private placement approximately 58.8 million shares of a new
class of convertible preferred stock and MESA will offer approximately 58.4
million shares of convertible preferred stock to MESA stockholders in a
rights offering (the "Rights Offering"). Rainwater will provide a standby
commitment to purchase any shares of preferred stock not subscribed to in
the Rights Offering. Rights will be distributed to common stockholders on a
pro rata basis. The rights will allow the stockholder to purchase, in
respect of each share of common stock, approximately .91 shares of preferred
stock at $2.26 per share, the same per share price at which Rainwater will
purchase preferred shares. The rights will be transferrable and holders of
the rights will be offered over-subscription privileges for shares not
purchased by other rights holders.
Each preferred share will be convertible into one share of MESA common
stock at any time prior to mandatory redemption in 2006. An annual 8% pay-
in-kind dividend will be paid on the preferred shares during the first four
years following issuance. Thereafter, the 8% dividend may, at the option of
MESA, be paid in cash or additional shares depending on whether certain
financial tests are met.
The preferred stock will represent 63.6% of the fully diluted common
shares at the time of issuance and 70.6% after the mandatory four-year pay-
in-kind period, assuming no other stock issuance by MESA. The preferred
stock will have a liquidation price equal to the purchase price. The
preferred shares purchased in the Rights Offering will vote with the common
stock as a single class on all matters, except as otherwise required by law
and except for certain special voting rights for shares held by Rainwater.
Rainwater will be entitled to elect two members of MESA's Board, which
will have seven directors. The Rainwater designees will constitute two of
the three members of a newly formed executive committee of the Board. The
executive committee will act for the whole Board on matters which by law do
not need Board authorization and will have authority over major capital
transactions, stock issuances, financing arrangements, budgeting, and other
items.
During an interim 30-day period beginning February 28, 1996, MESA, with
assistance from Rainwater, will seek commitments for new bank loans plus
assurance of availability of new subordinated debt to be issued in
conjunction with the transaction. Proceeds from the new debt, when combined
with proceeds from the newly issued equity and MESA's available cash
balances, would refinance or repay all of MESA's existing debt.
The proposed transaction is subject to certain conditions, including
negotiation and execution of definitive agreements, arrangement of the new
debt financing, due diligence by Rainwater and MESA stockholder approval.
The parties anticipate executing definitive agreements in about 30 days.
The transaction will be submitted to a vote of stockholders at a special
meeting expected to take place in June 1996. The Rights Offering would
commence promptly after that meeting. There can be no assurance that this
transaction will be completed, or if completed, what the final terms or
timing thereof will be. Nor can there be any assurance regarding the
availability or terms of any refinancing debt.
The ability of MESA to continue as a going concern is dependent upon
several factors. The successful completion of the Rainwater transaction is
expected to position MESA to continue as a going concern and to pursue its
business strategies. The consolidated financial statements of MESA do not
include any adjustments reflecting any treatment other than going concern
accounting.
If the Rainwater transaction is not completed, MESA will pursue other
alternatives to address its liquidity issues and financial condition,
including other potential transactions arising from the proposal
solicitation process, the possibility of seeking to restructure its balance
sheet by negotiating with its current debt holders or seeking protection
from its creditors under the Federal Bankruptcy Code.
Other
- -----
See Note 9 to the consolidated financial statements of the Company
included elsewhere in this Form 10-K for information regarding the status of
certain pending litigation.
In March 1995 the Financial Accounting Standards Board (the "FASB")
issued Statement of Financial Accounting Standards ("SFAS") No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of," which establishes accounting standards for the
impairment of long-lived assets, certain identifiable intangibles and
goodwill. (See Note 1 to the consolidated financial statements of the
Company included elsewhere in this Form 10-K for discussion of this
accounting standard.)
MESA recognizes its ownership interest in natural gas production as
revenue. Actual production quantities sold may be different from MESA's
ownership share of production in a given period. MESA records these
differences as gas balancing receivables or as deferred revenue. Net gas
balancing underproduction represented approximately 2% of total equivalent
production for the year ended December 31, 1995, compared with 5% during the
same period in 1994 and 3% in 1993. The gas balancing receivable or
deferred revenue component of natural gas and natural gas liquids revenues
in future periods is dependent on future rates of production, field
allowables and the amount of production taken by MESA or by its joint
interest partners.
MESA invests from time to time in marketable equity and other
securities, as well as in energy-related commodity futures contracts, which
include NYMEX futures contracts, price swaps and options. MESA also enters
into natural gas futures contracts as a hedge against natural gas price
fluctuations.
Management does not anticipate that inflation will have a significant
effect on MESA's operations.
Item 8. Consolidated Financial Statements and Supplementary Data
=================================================================
The consolidated financial statements of the Company, and notes
thereto, together with the report of Arthur Andersen LLP, MESA's independent
public accountants, dated March 6, 1996, and supplementary data are included
in this Form 10-K under Item 14 on pages F-2 through F-8.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
========================================================================
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
============================================================
Directors
---------
The following table sets forth each person on the Board of Directors of
the Registrant, (i) his name and age, (ii) the period during which he has
served as a director, and (iii) his principal occupation over the last five
years (including other directorships and business experience):
Business Experience
Name and Age Over Past Five Years
------------------------ ------------------------------
Boone Pickens, age 67.................. January 1992-Present, Chairman
of the Board of Directors and
Chief Executive Officer of the
Company; October 1985-December
1991, General Partner of Mesa
Limited Partnership (prede-
cessor to the Company and
hereinafter referred to as the
"Partnership") and Chief
Executive Officer and Director
of Pickens Operating Co., (the
corporate general partner of
the Partnership); 1964-January
1987, Chairman of the Board,
President, and founder of Mesa
Petroleum Co. (predecessor to
the Partnership, hereinafter
referred to as "Original
Mesa").
Paul W. Cain, age 57................... January 1992-Present, Director,
President and Chief Operating
Officer of the Company; August
1986-December 1991, President
and Chief Operating Officer of
Pickens Operating Co.; Director
of Bicoastal Corporation.
John S. Herrington, age 56............. January 1992-Present, Director
of the Company; December 1991
-Present, personal investments
and real estate activities; May
1990-November 1991, Chairman of
the Board of Harcourt Brace
Jovanovich, Inc. (publishing);
May 1989-May 1990, Director of
Harcourt Brace Jovanovich,
Inc.; February 1985-January
1989, Secretary of the
Department of Energy of the
United States.
Wales H. Madden, Jr., age 68........... January 1992-Present, Director
of the Company; December 1985
-December 1991, Member of the
Advisory Committee of the
Partnership; 1964-January 1987,
Director of Original Mesa; Self
-employed attorney and
businessman for more than the
last five years; Director of
Boatmen's First National Bank
of Amarillo.
Dorn Parkinson, age 49..................May 1995-Present, Director of
the Company; April 1986-
Present, President of
Washington Corporations
(principal businesses of
Washington Corporations and its
affiliates include rail
transport, mining, ship
berthing, environmental
remediation, interstate
trucking, and the repair and
sale of machinery and
equipment); January 1995-
Present, Chairman of the Board
of Kasler Holding Company
(heavy construction and
contract mining); July 1993-
October 1994, President and
Chief Operating Officer of
Kasler Holding Company;
Director of Kasler Holding
Company.
Joel L. Reed, age 45....................September 1995-Present,
Director of the Company;
August 1994-Present, partner
with Batchelder & Partners,
Inc.; October 1984-July 1994,
various capacities including
Chief Financial Officer,
President and Chief Executive
Officer of Wagner and Brown,
Ltd. and affiliates (privately
owned company consisting of
companies engaged in energy,
real estate, manufacturing,
agribusiness, and investment
services); Director of Magnetic
Delivered Therapeutics.
Fayez S. Sarofim, age 67............... January 1992-Present, Director
of the Company; Chairman of the
Board and President of Fayez
Sarofim & Co. (investment
adviser) for more than the last
five years; Director of
Teledyne, Inc., Unitrin, Inc.,
Argonaut Group, Inc., and
Imperial Holly Corporation.
Robert L. Stillwell, age 59............ January 1992-Present, Director
of the Company; December 1985
-December 1991, Member of the
Advisory Committee of the Part-
nership; 1969-January 1987,
Director of Original Mesa;
Partner in the law firm of
Baker & Botts, L.L.P., for more
than the last five years.
Executive Officers
------------------
The following table sets forth the name, age, and five-year employment
history of each Executive Officer of the Company:
Business Experience
Name and Age Over Past Five Years
------------------------ ------------------------------
Boone Pickens, age 67.................. January 1992-Present, Chairman
of the Board of Directors and
Chief Executive Officer of the
Company; October 1985-December
1991, General Partner of the
Partnership and Chief Executive
Officer and Director of Pickens
Operating Co.; 1964-January
1987, Chairman of the Board,
President, and founder of
Original Mesa.
Paul W. Cain, age 57................... January 1992-Present, Director,
President and Chief Operating
Officer of the Company; August
1986-December 1991, President
and Chief Operating Officer of
Pickens Operating Co.; Director
of Bicoastal Corporation.
Dennis E. Fagerstone, age 47........... January 1992-Present, Vice
President-Exploration and
Production of the Company; May
1991-December 1991, Vice
President-Exploration and
Production of Pickens Operating
Co.; June 1988-May 1991, Vice
President-Operations of Pickens
Operating Co.
Stephen K. Gardner, age 36............. June 1994-Present, Vice
President and Chief Financial
Officer of the Company; January
1992-May 1994, Vice President
of BTC Partners Inc. (financial
consultant to the Company); May
1988-December 1991, Financial
Analyst of BTC Partners, Inc.;
June 1987-April 1988, Financial
Analyst of the Partnership;
Director of Bicoastal
Corporation.
Andrew J. Littlefair, age 35........... January 1992-Present, Vice
President-Public Affairs of the
Company; August 1987-December
1991, Assistant to the General
Partner of the Partnership;
January 1984-August 1987, Staff
Assistant to the President of
the United States, Washington,
D.C.
William D. Ballew, age 37.............. January 1992-Present, Con-
troller of the Company; May
1991-December 1991, Controller
of the Partnership; January
1991-May 1991, Manager-
Accounting of Pickens Operating
Co.; December 1988-December
1990, Assistant to the
Controller of Pickens Operating
Co.; July 1986-December 1988,
Audit Manager for Price
Waterhouse, Dallas, Texas.
Item 11. Executive Compensation
================================
The table set forth below contains certain information regarding
compensation earned by, awarded to, or paid to the Chief Executive Officer
and the other four most highly compensated executive officers of the Company
for services rendered to the Company during the years 1993, 1994 and 1995.
Summary Compensation Table
--------------------------
Annual Compensation
----------------------------------
Other Annual
Name and Principal Position Year Salary Bonus Compensation(1)
- -------------------------------- ---- -------- -------- ------------
Boone Pickens, 1995 $675,000 $ 0 $ --
Chairman of the Board of 1994 675,000 175,000 --
Directors and Chief Executive 1993 675,000 0 --
Officer
Paul W. Cain, 1995 400,020 0 --
President and Chief Operating 1994 400,020 150,000 --
Officer 1993 400,020 225,000 --
Dennis E. Fagerstone, 1995 199,980 50,000 --
Vice President-Exploration 1994 199,980 100,000 --
and Production 1993 199,980 75,000 --
Stephen K. Gardner, 1995 175,020 40,000 --
Vice President and Chief 1994(8) 92,095 60,000 --
Financial Officer 1993 -- -- --
Andrew J. Littlefair, 1995 139,980 40,000 --
Vice President-Public Affairs 1994 115,980 100,000 --
1993 115,980 75,000 --
Long-Term
Compensation
Awards-Number
of Shares
Underlying All Other
Name and Principal Position Year Options/SARs Compensation(2)
- -------------------------------- ---- --------------- ---------------
Boone Pickens, 1995 0 $ 35,914(3)
Chairman of the Board of 1994 200,000 1,094,500(4)
Directors and Chief Executive 1993 275,000 114,750
Officer
Paul W. Cain, 1995 0 22,165(5)
President and Chief Operating 1994 150,000 93,503
Officer 1993 100,000 106,253
Dennis E. Fagerstone, 1995 0 14,663(6)
Vice President-Exploration 1994 85,000 50,997
and Production 1993 10,000 46,747
Stephen K. Gardner, 1995 0 12,915(7)
Vice President and Chief 1994(8) 135,000 25,856
Financial Officer 1993 -- --
Andrew J. Littlefair, 1995 0 11,163(9)
Vice President-Public Affairs 1994 85,000 36,717
1993 25,000 32,467
(1) Apart from the compensation set forth in the summary compensation table
and under the plans and pursuant to the transactions described below,
other compensation paid for services during the years ended December
31, 1995, 1994, and 1993, respectively, to each individual named in the
summary compensation table aggregated less than 10% of the total salary
and bonus reported for such individual in the summary compensation
table, or $50,000, if lower.
(2) Except as reflected in other notes, "All Other Compensation" consists
of the following items. First, the Company maintains an Employees
Premium Plan and a Profit Sharing Plan, both of which are retirement
plans (the "Retirement Plans"), for all employees (see separate
discussion below). The Company declared contributions to the
Retirement Plans of 5% of each employee's compensation in 1995 and 17%
of each employee's compensation in 1994 and 1993. However, total
employer contributions to the Retirement Plans for the account of a
participant in any calendar year are limited as specified by the
Internal Revenue Code (the "Code") and the Retirement Plans. See
"Limitation on Contributions to Benefit Plans" below. The maximum
annual amount of employer contributions to a participant's accounts in
the Retirement Plans totaled $7,500 in 1995, $25,500 in 1994, and
$30,000 in 1993. Second, to the extent that 5% of an employee's total
compensation exceeded $7,500 in 1995, that 17% of an employee's total
compensation exceeded $25,500 in 1994 (in both cases, all employees
with total compensation in excess of $150,000), and that 17% of an
employee's total compensation exceeded $30,000 in 1993 (all employees
with total compensation in excess of $176,470), the Company, as a
matter of policy, paid the excess amount in cash to such employee.
Third, in 1995 there was a reallocation to participant accounts of
forfeitures in the Profit Sharing Plan from unvested balances in the
accounts of employees who terminated during 1994.
(3) Includes the following: a $7,500 Retirement Plans contribution; a
$2,164 reallocation of forfeitures in the Profit Sharing Plan; a
$26,250 payment in lieu of a Retirement Plans contribution in excess of
the contribution limitation as described in Note 2 above.
(4) Includes the following: a $25,500 Retirement Plans contribution; a
$119,000 payment in lieu of a Retirement Plans contribution in excess
of the contribution limitation as described in Note 2 above; a $950,000
bonus payment that has been deferred until Mr. Pickens' retirement and
that was subject to his continued employment (except in certain events)
through December 31, 1995, with respect to the Company's 1994
commodities and securities investment activities managed by him.
(5) Includes the following: a $7,500 Retirement Plans contribution; a
$2,164 reallocation of forfeitures in the Profit Sharing Plan; a
$12,501 payment in lieu of a Retirement Plans contribution in excess
of the contribution limitation as described in Note 2 above.
(6) Includes the following: a $7,500 Retirement Plans contribution; a
$2,164 reallocation of forfeitures in the Profit Sharing Plan; a $4,999
payment in lieu of a Retirement Plans contribution in excess
of the contribution limitation as described in Note 2 above.
(7) Includes the following: a $7,500 Retirement Plans contribution; a
$2,164 reallocation of forfeitures in the Profit Sharing Plan; a $3,251
payment in lieu of a Retirement Plans contribution in excess
of the contribution limitation as described in Note 2 above.
(8) Mr. Gardner became an officer of the Company in June 1994.
(9) Includes the following: a $7,500 Retirement Plans contribution; a
$2,164 reallocation of forfeitures in the Profit Sharing Plan; a $1,499
payment in lieu of a Retirement Plans contribution in excess
of the contribution limitation as described in Note 2 above.
Employees Premium and Profit Sharing Plans
- ------------------------------------------
MESA maintains the Retirement Plans for the benefit of its employees.
Each year, the Company is required to contribute to the Employees Premium
Plan 5% of the total compensation (as defined in the plan) paid to
participants and may also contribute up to 12% of total compensation (as
defined) to the Profit Sharing Plan. In previous years, the Company had
declared contributions of 17% to the Retirement Plans. In 1995 the Company
declared contributions of 5% to the Retirement Plans.
Participants become 30% vested in their account balances in the
Retirement Plans after three years of service and 40% vested after four
years of service. Participants become vested an additional 20% for each
additional year of service through year seven. Effective December 31, 1991,
in conjunction with the conversion of the Partnership to the Company (the
"Corporate Conversion"), all participants were fully vested in their account
balances in the Retirement Plans as of that date as a result of certain
property dispositions consummated in 1990 and 1991. Participants remain
fully vested in their 1991 balances, but contributions in 1992 and later
years under the Retirement Plans are subject to the vesting schedule
described above.
Prior years of service with the Company's predecessors are counted in
the vesting schedule. Amounts accumulated and vested are distributable only
under certain circumstances, including termination of the Retirement Plans.
Limitation on Contributions to Benefit Plans
- --------------------------------------------
Total employer contributions to the Retirement Plans for the account of
a participant in any calendar year are limited to the lesser of what is
specified by the Code or by the Retirement Plans. The Code provides that
annual additions to a participant's account may not exceed the lesser of
$30,000 or 25% of the amount of the participant's annual compensation. The
Retirement Plans provide that aggregate annual additions to a participant's
account may not exceed 17% of eligible compensation as defined by the
Retirement Plans. The eligible compensation per the Code was limited to
$150,000 in 1995, $150,000 in 1994, and $228,000 in 1993. The Company, in
its discretion, may determine to make cash payments of amounts attributable
to an employee's participation in the Retirement Plans to the extent such
amounts exceed the Code limitations. As a matter of general policy for
employees of the Company, the Company makes annual cash payments directly to
employees to the extent that the annual additions to the account of each
such employee pursuant to the Retirement Plans would exceed the Code
limitations.
1991 Stock Option Plan
- ----------------------
The 1991 Stock Option Plan (the "Option Plan") was approved by
stockholders in 1991 and amended by stockholders in 1994. Its purpose is to
serve as an incentive to, and aid in the retention of, key executives and
other employees whose training, experience, and ability are considered
important to the operations and success of the Company. The Option Plan is
administered by the Stock Option Committee composed of non-employee
directors of the Company who meet the requirements of "disinterested person"
in Rule 16b-3 (c)(2)(i) of the Securities Exchange Act of 1934. Pursuant to
the Option Plan, the Stock Option Committee is given the authority to
designate plan participants, to determine the terms and provisions of
options granted thereunder, and to supervise the administration of the plan.
A total of 4,000,000 shares of Common Stock are currently subject to the
plan, of which options for 3,062,950 shares have been granted. At December
31, 1995, the following stock options were outstanding:
Number of
Options
---------
Granted.................................................... 3,062,950
Exercised.................................................. (62,720)
Forfeited.................................................. (67,840)
---------
Outstanding at December 31, 1995........................... 2,932,390
=========
Shares of Common Stock subject to an option are awarded at an exercise
price that is equivalent to at least 100% of the fair market value of the
Common Stock on the date the option is granted. The purchase price of the
shares as to which the option is exercised is payable in full at exercise in
cash or in shares of Common Stock previously held by the optionee for more
than six months, valued at their fair market value on the date of exercise.
Subject to Stock Option Committee approval and to certain legal limitations,
an optionee may pay all or any portion of the purchase price by electing to
have the Company withhold a number of shares of Common Stock having a fair
market value equal to the purchase price. Options granted under the Option
Plan include a limited right of relinquishment that permits an optionee, in
lieu of purchasing the entire number of shares subject to purchase
thereunder and subject to consent of the Stock Option Committee, to
relinquish all or part of the unexercised portion of an option, to the
extent exercisable, for cash and/or shares of Common Stock in an amount
representing the appreciation in market value of the shares subject to such
options over the exercise price thereof. In its discretion, the Stock
Option Committee may provide for the acceleration of any unvested
installments of outstanding options. The Board of Directors may amend,
alter, or discontinue the Option Plan, subject in certain cases to
stockholder approval.
The options granted and outstanding at December 31, 1995, have exercise
prices and vesting schedules as set forth in the following table:
Exercise Vesting Schedule
Number of Price Per --------------------------------------------
Options Share 30% 55% 80% 100%
- --------- --------- -------- -------- -------- --------
1,126,000 $ 6.8125 07/10/92 01/10/93 01/10/94 01/10/95
134,500 11.6875 04/02/93 10/02/93 10/02/94 10/02/95
101,890 5.8125 11/18/93 05/18/94 05/18/95 05/18/96
475,000 7.3750 05/10/94 11/10/94 11/10/95 11/10/96
75,000 6.1875 12/06/94 06/06/95 06/06/96 06/06/97
1,000,000 4.2500 06/01/95 12/01/95 12/01/96 12/01/97
20,000 5.6875 11/12/95 05/12/96 05/12/97 05/12/98
There were no options granted to the Chief Executive Officer or to the
other four most highly compensated executive officers of the Company during
1995.
Options exercised in 1995, and the number and value of exercisable and
unexercisable options at December 31, 1995, for the Chief Executive Officer
and the other four most highly compensated executive officers of the Company
are as follows:
Aggregated Option/SAR Exercises in Last Fiscal Year and Fiscal Year End
Option/SAR Values
-----------------------------------------------------------------------
Year Ended December 31, 1995
----------------------------------------------
Number of Shares Acquired
Name on Exercise Value Realized
- ------------------------- ------------------------- --------------
Boone Pickens -- $ --
Paul W. Cain -- --
Dennis E. Fagerstone -- --
Stephen K. Gardner -- --
Andrew J. Littlefair -- --
Value of Unexercised
Number of Shares Underlying In-the-Money
Unexercised Options/SARs at Options/SARs at
December 29, 1995 December 29, 1995
--------------------------- ------------------------
Exercisable Unexercisable Exercisable Unexercisable
- --------------------- ----------- ------------- ----------- ------------
Boone Pickens 1,130,000 145,000 $ 0 $ 0
Paul W. Cain 312,500 87,500 0 0
Dennis E. Fagerstone 104,750 40,250 0 0
Stephen K. Gardner 74,250 60,750 0 0
Andrew J. Littlefair 96,750 43,250 0 0
At December 29, 1995, the final trading day of the year, the Company's
Common Stock per share closed at $3.75. The exercise price of the four
grants of stock options reflected in the aggregate in the above tables are
$6.8125, $7.375, $6.1875, and $4.25, respectively, per share. Thus, no
outstanding options were in-the-money at such date.
Other
- -----
There were no awards made under any long-term incentive plans from
January 1, 1995, through December 31, 1995; therefore, no disclosure is
required in the Long-Term Incentive Plan Awards table. From January 1,
1995, through December 31, 1995, no options or stock appreciation rights
were repriced (as defined in Item 402(i) of Regulation S-K of the Securities
Act of 1933). Except as described below under "Employee Retention
Provisions," the Company does not have any employment contracts or
termination or change-in-control arrangements with respect to a named
executive officer of the Company that would require disclosure pursuant to
Item 402(h) of Regulation S-K.
Common Stock Purchase Plan
- --------------------------
The Company has established a Common Stock purchase program whereby
employees, except officers, can buy Common Stock through after-tax payroll
deductions. All other full-time employees of the Company and its
participating affiliates are eligible to participate. The Company pays the
brokerage fees for these open-market transactions.
Employee Retention Provisions
- -----------------------------
On August 22, 1995, the Board of Directors adopted the MESA Inc. Change
in Control Retention/Severance Plan, as amended, (the "Retention Plan").
Pursuant to the Retention Plan, all regular employees of the Company (other
than Mr. Pickens) will be entitled to receive certain benefits upon the
occurrence of certain involuntary termination events (as described below)
following a "Change in Control" (as defined below) of the Company. The
severance benefits consist of 200% of defined pay for officers (which
includes the highest salary and highest bonus during the then-current and
prior three calendar years before the Retention Plan was adopted), 150% of
defined pay for certain key employees (which includes salary and bonus
amounts) and a formula-based amount for all other employees, plus, in each
case, any other accrued or vested or earned but deferred compensation,
rights, options, or benefits otherwise owed to such employee upon his
termination. In addition, on the same date, the Board of Directors' Stock
Option Committee determined that all outstanding but unvested stock options
granted to an employee under the Company's 1991 Stock Option Plan would
immediately vest and become exercisable upon such a termination event
following a Change in Control.
The Company developed the Retention Plan in consultation with an
independent compensation consultant. That consulting firm advised the Board
of Directors that the Retention Plan is conservatively in line with common
practices. The independent firm noted, among other things, that most such
plans it surveyed provide officers with three times their defined pay,
rather than two.
For purposes of the Retention Plan, a "Change in Control" means (i) any
acquisition by an individual, entity or group resulting in such person's
obtaining beneficial ownership of 35% or more of the then outstanding Common
Stock or the combined voting power of the then outstanding voting securities
of the Company entitled to vote in an election of directors, provided
certain acquisitions, including the following, shall not in and of
themselves constitute a Change in Control hereunder: (a) any acquisition of
securities of the Company made directly from the Company and approved by a
majority of the directors then comprising the members of the Board of
Directors as of May 16, 1995 (the "Incumbent Board"); or (b) any acquisition
of beneficial ownership of a higher percentage of the Common Stock
outstanding of the Company or the Voting Securities of the Company that
results solely from the acquisition, purchase or redemption of securities of
the Company by the Company so long as such action by the Company was
approved by a majority of the directors then comprising the Incumbent Board;
(ii) a change in the membership of the Incumbent Board, together with
members elected subsequent to May 16, 1995, whose election or nomination for
election was approved by a majority of the members of the Incumbent Board as
then constituted (excluding for this purpose any individual whose initial
assumption of office occurred as a result of an actual or threatened
election contest), cease for any reason to constitute a majority of the
Board of Directors; (iii) a reorganization, merger, consolidation or sale of
all or substantially all of the assets of the Company, subject to certain
exceptions; or (iv) approval by the stockholders of the Company of the
complete liquidation or dissolution of the Company.
Following the occurrence of a Change in Control, an eligible employee
would be entitled to receive full severance benefits if, within 24 months of
the occurrence of a Change in Control: (i) the employee was terminated by
the Company without "Cause" (as defined below); or (ii) the employee's
duties, responsibilities or rate of pay as an employee were materially and
adversely diminished in comparison to the duties, responsibilities and rate
of pay enjoyed by the employee on the effective date of the Retention Plan;
or (iii) the employee was relocated to any location in excess of 35 miles
from his location immediately prior to the Change in Control. All severance
benefits with respect to an eligible employee are payable in a lump sum
within ten days after the termination date of such employee. Under the
Retention Plan, "Cause" means the willful and continued failure of an
employee to perform substantially the employee's duties with the Company
following written demand for performance or the willful engaging by the
employee in illegal conduct or gross misconduct that is materially and
demonstrably injurious to the Company.
Director Compensation and Certain Relationships
- -----------------------------------------------
Each director of the Company serving throughout 1995 who was not also
an employee of the Company or its subsidiaries received compensation of
$20,000 allocated quarterly in 1995, except for Messrs. Parkinson, David H.
Batchelder and Reed (who succeeded Mr. Batchelder). Mr. Parkinson received
$15,000, Mr. Batchelder received $10,000, and Mr. Reed received $5,000 for
serving as directors for approximately seven months, four months, and three
months, respectively. Directors who are also employees of the Company
receive no remuneration for their services as directors.
Mr. Sarofim, a director and member of the Compensation and Stock Option
Committees, is Chairman of the Board, President, and owner of a majority of
the outstanding capital stock of Fayez Sarofim & Co., which acts as an
investment adviser to certain employee benefit plans of the Company. During
the year ended December 31, 1995, Fayez Sarofim & Co. received fees, paid by
the employee benefit plans, of $175,459 for such services and has been
retained to provide such services in 1996.
Mr. Stillwell, a director, is a partner in the law firm of Baker &
Botts, L.L.P. The Company retained Baker & Botts, L.L.P., and incurred
legal fees for such services in 1995. Baker & Botts, L.L.P., has been
retained to provide legal services in 1996.
Compensation Committee Interlocks and Insider Participation
- -----------------------------------------------------------
The Compensation Committee is composed of Messrs. Sarofim and Reed.
The Stock Option Committee, which administers the 1991 Stock Option Plan, is
also composed of Messrs. Sarofim and Reed. Mr. Sarofim is Chairman of the
Board, President, and owner of a majority of the outstanding capital stock
of Fayez Sarofim & Co., which acts as an investment adviser for certain
amounts invested in certain funds in the Retirement Plans. During the year
ended December 31, 1995, Fayez Sarofim & Co. received fees, paid by the
Retirement Plans, of $175,459 for such services and has been retained to
provide such services in 1996. Mr. Stillwell and former directors Jerry
Walsh and David Batchelder served on the committees during 1995, but ceased
to serve on the committees prior to the time the committees met to
deliberate executive officer compensation.
Indemnification Arrangements
- ----------------------------
The Company's Bylaws provide for the indemnification of its executive
officers and directors, and the advancement to them of expenses in
connection with proceedings and claims, to the fullest extent permitted by
the Texas Business Corporation Act. The Company has also entered into
indemnification agreements with its executive officers and directors that
contractually provide for indemnification and expense advancement and
include related provisions meant to facilitate the indemnitees' receipt of
such benefits. In addition, the Company purchased customary directors' and
officers' liability insurance policies for its directors and officers. The
Bylaws and agreements with directors and officers also provide for
indemnification for amounts (i) in respect of the deductibles for such
insurance policies, (ii) that exceed the liability limits of such insurance
policies, and (iii) that would have been covered by prior insurance policies
of the Company or its predecessors. Such indemnification may be made even
though directors and officers would not otherwise be entitled to
indemnification under other provisions of the Bylaws or such agreements.
Item 12. Security Ownership of Certain Beneficial Owners and Management
========================================================================
Security Ownership of Management
- --------------------------------
The following table presents certain information as to the beneficial
ownership of the Company's Common Stock as of March 6, 1996, by the
directors, director nominees, and officers of the Company, individually and
as a group:
Number of
Shares of Percentage
Common of Common
Stock(1) Stock
---------- ----------
Directors:
Paul W. Cain.............................. 322,639 *
John S. Herrington........................ 10,000 *
Wales H. Madden, Jr. ..................... 22,200 *
Boone Pickens(2).......................... 5,061,626 7.8%
Fayez S. Sarofim.......................... 1,400,000 2.2%
Robert L. Stillwell....................... 26,500 *
Dorn Parkinson(3)......................... - *
Joel L. Reed.............................. - *
Officers:
Dennis E. Fagerstone...................... 104,750 *
Stephen K. Gardner........................ 90,479 *
Andrew J. Littlefair(4)................... 113,438 *
William D. Ballew......................... 64,853 *
Directors, and Officers as a
group (12 persons)............................. 7,216,485 11.0%
* Less than 1.0%
(1) Includes shares issuable upon the exercise of options that are
exercisable within sixty days of March 6, 1996, as follows:
1,130,000 shares for Mr. Pickens; 312,500 for Mr. Cain; 104,750 for Mr.
Fagerstone; 74,250 for Mr. Gardner; 96,750 for Mr. Littlefair; 62,750
for Mr. Ballew; and 1,781,000 for all directors and officers as a
group.
(2) The above amount includes 7,545 shares of Common Stock owned by several
trusts for Mr. Pickens' children of which he is a trustee, and over
which shares he has sole voting and investment power, although he has
no economic interest therein. The above amounts exclude 2,798 shares
of Common Stock owned by Mrs. Pickens as her separate property, as to
which Mr. Pickens disclaims beneficial ownership and with respect to
which he does not have or share voting or investment power.
(3) Excludes 3,800 shares of Common Stock owned by Mr. Parkinson's son as
his separate property, as to which Mr. Parkinson disclaims beneficial
ownership and with respect to which he does not have or share voting or
investment power. Mr Parkinson is a member of a group consisting of
Dennis R. Washington, Marvin Davis, Davis Acquisition, L.P., Davis
Companies, the Marvin Davis and Barbara Davis Revocable Trust, David H.
Batchelder, and Dorn Parkinson (the "13D Group") which has filed a
Scheduled 13D stating that the 13D Group is the beneficial owner of
6,000,000 shares of Common Stock. See Note 3 to the table under
"Certain Beneficial Owners."
(4) Excludes 1,125 shares of Common Stock owned by Mrs. Littlefair as her
separate property, as to which Mr. Littlefair disclaims beneficial
ownership and with respect to which he does not have or share voting or
investment power.
Certain Beneficial Owners
- -------------------------
The table below sets forth certain information as of March 6, 1996,
regarding each person or "group" (as that term is used in Section 13(d)(3)
of the Securities Exchange Act of 1934) known by the Company to own
beneficially more than 5% of the Common Stock. Information is based on the
most recent Schedule 13D or 13G filed by such holder with the Securities and
Exchange Commission (the "SEC"), or other information provided by the holder
to the Company.
Amount and Nature of
Beneficial Ownership
-------------------------------
Number of Percentage
Name and Address of Shares of of Common
Beneficial Owner Common Stock Stock
------------------- ------------ ----------
Boone Pickens.......................... 5,061,626(1) 7.8%
1400 Williams Square West
5205 North O'Connor Boulevard
Irving, Texas 75039-3746
FMR Corp. ............................. 5,140,400(2) 8.0%
82 Devonshire Street
Boston, Massachusetts 02109
13D Group.............................. 6,000,000(3) 9.4%
c/o Dennis R. Washington
Washington Corporations
101 International Way
Missoula, Montana 59807
(1) See notes (1) and (2) to the table under "Security Ownership of
Management."
(2) The Schedule 13G filed with the SEC on February 14, 1996, by FMR Corp.
states that as of December 31, 1995, Fidelity Management & Research
Company ("Fidelity"), a wholly owned subsidiary of FMR Corp. and an
investment adviser registered under Section 203 of the Investment
Advisers Act of 1940, is the beneficial owner of 5,140,400 shares or
8.0% of Common Stock as a result of acting as investment adviser to
various investment companies registered under Section 8 of the
Investment Company Act of 1940.
The ownership of one investment company, Fidelity Capital Appreciation
Fund ("Fund"), amounted to 5,140,400 shares or 8.0% of Common Stock
outstanding. Edward C. Johnson, III, chairman of FMR Corp., FMR Corp.,
through its control of Fidelity, and the Fund each has sole power to
dispose of the 5,140,400 shares owned by the Fund.
(3) A Schedule 13D filed by the 13D Group on June 29, 1995, as amended,
states that such group beneficially owns 6,000,000 shares of Common
Stock. The Schedule 13D states that Dennis R. Washington has sole
voting power over 3,500,000 shares and that Davis Acquisition, L.P.,
Davis Companies, the Marvin Davis and Barbara Davis Revocable Trust,
and Marvin Davis have shared voting power over 2,500,000 of such
shares.
Item 13. Certain Relationships and Related Transactions
========================================================
The information in Item 11 above, "Executive Compensation," is
incorporated by reference herein. Except as described thereunder, no
reportable transaction occurred in 1995.
<PAGE>
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
==========================================================================
(a)(1) Consolidated Financial Statements and Supplementary Data
- ----------------------------------------------------------------
Page in Form 10-K
-----------------
Report of Independent Public Accountants........... F-2
Consolidated Statements of Operations.............. F-3
Consolidated Balance Sheets........................ F-4
Consolidated Statements of Cash Flows.............. F-5
Consolidated Statements of Changes
in Stockholders' Equity.......................... F-6
Notes to Consolidated Financial Statements......... F-7
Supplemental Financial Data........................ F-8
(a)(2) Consolidated Financial Statement Schedules
- --------------------------------------------------
The consolidated financial statement schedules have been omitted
because they are not required, are not applicable or the information
required has been included elsewhere herein.
(a)(3) Exhibits
- ----------------
(Asterisk indicates exhibits are incorporated by reference herein).
*2.1 - Rainwater, Inc. letter of intent dated February 27, 1996,
between MESA Inc. and Rainwater, Inc.(Exhibit no. 2 to the
Company's Form 8-K filed March 1, 1996).
*3.1 - Amended and Restated Articles of Incorporation of MESA Inc.
dated December 31, 1991 (Exhibit 3[a] to the Company's Form
10-K dated December 31, 1991).
*3.2 - Amended and Restated Bylaws of MESA Inc. (Exhibit 3[c] to
the Company's Registration Statement on Form S-4,
Registration No. 33-42102).
*4.1 - Indenture dated as of May 1, 1993, among MESA Inc., MESA
Operating Limited Partnership, Mesa Capital Corporation and
Harris Trust and Savings Bank, as Trustee, relating to the
secured discount notes and including (a) a form of Secured
Notes, (b) a form of Deed of Trust, Assignment of
Production, Security Agreement and Financing Statement,
dated as of May 1, 1993, between Mesa Operating Limited
Partnership and Harris Trust and Savings Bank, as trustee,
securing the Secured Notes, and (c) a form of Security
Agreement, Pledge and Financing Statement dated as of May 1,
1993, between Mesa Operating Limited Partnership and Harris
Trust and Savings Bank, as trustee, securing the Secured
Notes (Exhibit 4[f] to the Company's Form 10-Q/A dated June
30, 1993).
*4.2 - First Supplemental Indenture dated as of January 5, 1994,
among MESA Inc., Mesa Operating Co., Mesa Capital Corporation
and Harris Trust and Savings Bank, as Trustee (Exhibit 4.2 to
the Company's Registration Statement on Form S-1,
Registration No. 33-51909).
*4.3 - First Supplement to Security Agreement, Pledge and Financing
Statement dated as of March 2, 1994, by Mesa Operating Co. in
favor of Harris Trust and Savings Bank, as Trustee for the
pro rata benefit of the Noteholders under the Indenture
(Exhibit 4.9 to the Company's Form 10-Q dated March 31,
1994).
*4.4 - Indenture dated as of May 1, 1993, among MESA Inc., MESA
Operating Limited Partnership, Mesa Capital Corporation and
American Stock Transfer & Trust Company, as Trustee, relating
to the unsecured discount notes (Exhibit 4[g] to the
Company's Form 10-Q/A dated June 30, 1993).
*4.5 - First Supplemental Indenture dated as of January 5, 1994,
among MESA Inc., Mesa Operating Co., Mesa Capital Corporation
and American Stock Transfer & Trust Company, as Trustee
(Exhibit 4.4 to the Company's Registration Statement on Form
S-1, Registration No. 33-51909).
*4.6 - Indenture dated May 1, 1989, among Mesa Capital Corporation,
Mesa Limited Partnership, Mesa Operating Limited Partnership,
and Texas Commerce Bank National Association, as Trustee
(Exhibit 4[c] to the Partnership's Form 10-Q dated March 31,
1989).
*4.7 - First Supplemental Indenture dated as of December 31, 1991,
among Mesa Capital Corporation, MESA Inc., Mesa Operating
Limited Partnership, as Issuers, and Texas Commerce Bank
National Association, as Trustee (Exhibit 4[e] to the
Company's Form 10-K dated December 31, 1991).
*4.8 - Second Supplemental Indenture dated as of April 30, 1992,
among Mesa Capital Corporation, MESA Inc., Mesa Operating
Limited Partnership and Texas Commerce Bank National
Association, as Trustee (Exhibit 4[k] to the Company's Form
10-Q dated June 30, 1992).
*4.9 - Third Supplemental Indenture dated as of August 26, 1993,
among Mesa Capital Corporation, MESA Inc., Mesa Operating
Limited Partnership and Texas Commerce Bank National
Association, as Trustee (Exhibit 4[l] to the Company's Form
10-Q/A dated June 30, 1993).
*4.10 - Fourth Supplemental Indenture dated as of January 5, 1994,
among MESA Inc., Mesa Operating Co., Mesa Capital Corporation
and Texas Commerce Bank National Association, as Trustee
(Exhibit 4.16 to the Company's Registration Statement on Form
S-1, Registration No. 33-51909).
*4.11 - Indenture dated as of May 30, 1991, among Hugoton Capital
Limited Partnership, Hugoton Capital Corporation and Bankers
Trust Company (Exhibit 4[e] to the Partnership's Form 10-Q
dated June 30, 1991).
*4.12 - First Supplemental Indenture dated September 1, 1991, among
Hugoton Capital Limited Partnership, Hugoton Capital
Corporation and Bankers Trust Company, as Trustee (Exhibit
4[h] to the Company's Registration Statement on Form S-4,
Registration No. 33-42102).
*4.13 - Amended and Restated Mortgage, Assignment, Security Agreement
and Financing Statement dated June 12, 1991, from Hugoton
Capital Limited Partnership to Bankers Trust Company, as
Collateral Agent (Exhibit 4[f] to the Partnership's Form 10-Q
dated June 30, 1991).
*4.14 - Third Amended and Restated Credit Agreement dated as of
November 29, 1994, among the Company, Mesa Operating Co., and
the Banks named in this Credit Agreement and Societe
Generale, Southwest Agency, as Agent (Exhibit 4.7 to the
Company's Form 10-K dated December 31, 1994).
*4.15 - Intercreditor Agreement dated as of August 26, 1993, among
Societe Generale, Southwest Agency, as agent for the Banks
under the Company's Credit Agreement, Harris Trust and
Savings Bank, as trustee with respect to the Secured Notes,
and American Stock Transfer & Trust Company, as trustee with
respect to the Unsecured Notes (Exhibit 4.18 to the Company's
Registration Statement on Form S-4, Registration No.
33-53706).
The Registrant agrees to furnish to the Commission upon
request any instruments defining the right of holders of
long-term debt with respect to which the total amount
outstanding does not exceed 10% of the total assets of the
Registrant and its subsidiaries on a consolidated basis.
*10.1 - Form of First Amendment to Deferred Compensation Agreement
and Life Insurance Agreement between MESA Petroleum Co. and
certain officers and key employees (Exhibit 10[i] to the
Company's Form 10-K dated December 31, 1980).
*10.2 - Contract dated January 3, 1928, between Colorado Interstate
Gas Company and Amarillo Oil Company (the "B" Contract)
(Exhibit 10.1 to Pioneer Corporation's Form 10-K dated
December 31, 1985).
*10.3 - Amendments to the "B" Contract (Exhibit 10.2 to Pioneer
Corporation's Form 10-K dated December 31, 1985).
*10.4 - Gathering Charge Agreement dated January 20, 1984, as
amended, with respect to the "B" Contract (Exhibit 10.3 to
Pioneer Corporation's Form 10-K dated December 31, 1985).
*10.5 - Agreement of Compromise and Settlement dated May 29, 1987,
between the Partnership and Colorado Interstate Gas Company
(Confidential Treatment Requested) (Exhibit 10[s] to the
Partnership's Form 10-K dated December 31, 1987).
*10.6 - Agreement of Sale between Pioneer Corporation and Cabot
Corporation dated August 29, 1984 (Exhibit 10.5 to Pioneer
Corporation's Form 10-K dated December 31, 1985).
*10.7 - Settlement Agreement dated March 15, 1989, by and among MESA
Operating Limited Partnership and Mesa Limited Partnership,
et al, Energas Company and the City of Amarillo (Exhibit
10[k] to the Partnership's Form 10-K dated December 31,
1990).
*10.8 - Gas Purchase Agreement dated December 1, 1989, between
Williams Natural Gas Company and Mesa Operating Limited
Partnership acting on behalf of itself and as agent for MESA
Midcontinent Limited Partnership (Exhibit 10.1 to
Registration Statement of the Partnership on Form S-3,
Registration No. 33-32978).
*10.9 - "B" Contract Production Allocation Agreement dated July 29,
1991, and effective as of January 1, 1991, between Colorado
Interstate Gas Company and Mesa Operating Limited
Partnership (Exhibit 10[r] to the Company's Form 10-K dated
December 31, 1991).
*10.10 - Amendment to "B" Contract Production Allocation Agreement
effective as of January 1, 1993, between Colorado Interstate
Gas Company and Mesa Operating Limited Partnership (Exhibit
10.24 to the Company's Registration Statement on Form S-1,
Registration No. 033-51909).
*10.11 - Amended Supplemental Stipulation and Agreement between
Colorado Interstate Gas Company and Mesa Operating Limited
Partnership dated June 19, 1991 (Exhibit 10[w] to the
Company's Registration Statement on Form S-4, Registration
No. 33-42102).
*10.12 - Amended Peak Day Gas Purchase Agreement dated effective June
19, 1991, between Colorado Interstate Gas Company and MESA
Operating Limited Partnership (Exhibit 10[t] to the
Company's Form 10-K dated December 31, 1991).
*10.13 - Omnibus Amendment to Collateral Instruments to Supplemental
Stipulation and Agreement dated June 19, 1991, between
Colorado Interstate Gas Company and Mesa Operating Limited
Partnership (Exhibit 10[u] to the Company's Form 10-K dated
December 31, 1991).
10.14 - Amarillo Supply Agreement between Mesa Operating Limited
Partnership, Seller, and Energas Company, a division of Atmos
Energy Corporation, Buyer, dated effective January 2, 1993.
10.15 - Gas Gathering Agreement-Interruptible between Colorado
Interstate Gas Company, Transporter, and Mesa Operating
Limited Partnership, Shipper, dated effective October 1,
1993, as amended by agreements dated January 1, 1994, January
5, 1994, and June 1, 1994.
10.16 - Gas Supply Agreement dated May 11, 1994, between Mesa
Operating Co., as successor to Mesa Operating Limited
Partnership, acting on behalf of itself and as agent for
Hugoton Capital Limited Partnership, and Williams Gas
Marketing Company, and Gas Supply Guarantee dated May 11,
1994.
*10.17 - Gas Transportation Agreement dated June 14, 1994, between
Western Resources, Inc. and Mesa Operating Co., acting on
behalf of itself and as agent for Hugoton Capital Limited
Partnership (Exhibit 10.24 to the Company's Form 10-K dated
December 31, 1994).
*10.18 - Incentive Bonus Plan of Mesa Operating Limited Partnership,
as amended, dated effective January 1, 1986 (Exhibit 10[s]
to the Partnership's Form 10-K dated December 31, 1990).
*10.19 - Performance Bonus Plan of Mesa Operating Limited Partnership
dated effective January 1, 1990 (Exhibit 10[t] to the
Partnership's Form 10-K dated December 31, 1990).
*10.20 - 1991 Stock Option Plan of MESA (Exhibit 10[v] to the
Company's Form 10-K dated December 31, 1991).
*10.21 - Split-Dollar Insurance Agreements dated June 29, 1992, by and
between Mesa Operating Limited Partnership and Boone Pickens
and Paul Cain, respectively, and Collateral Assignments
dated as of June 29, 1992, by Boone Pickens and Paul Cain,
respectively (Exhibit 10[aa] to the Company's Form 10-K
dated December 31, 1992).
10.22 - Interruptible Gas Transportation and Sales Agreement dated
January 1, 1991, between Mesa Operating Limited Partnership
and Energas Company and Amendment dated January 1, 1995.
10.23 - "B" Contract Operating Agreement dated January 1, 1988,
between Mesa Operating Limited Partnership and Colorado
Interstate Gas Company.
10.24 - "B" Contract Agreement of Compromise and Settlement dated
May 29, 1987, between Mesa Operating Limited Partnership and
Colorado Interstate Gas Company, and Amendment to Gathering
Agreement dated July 15, 1990.
10.25 - Gas Purchase Agreement dated January 1, 1996, between Mesa
Operating Co., as Seller, and KN Marketing L.P., as Buyer,
and Amendment dated August 1, 1995.
10.26 - Change in Control Retention/Severance Plan adopted August
22, 1995, and Amendment dated October 20, 1995.
22 - List of Subsidiaries of the Company.
27 - Article 5 of Regulation S-X Financial Data Schedule
for Year-End 1995 Form 10-K.
28 - Summary Report of the Company relating to proved oil and gas
reserves at December 31, 1995.
(b) Reports on Form 8-K
- ------------------------
Current Report on Form 8-K dated February 28, 1996, and filed March 1,
1996, regarding a letter of intent between the Company and Rainwater, Inc.,
relating to an equity investment to be made in connection with the
refinancing of all the Company's debt.
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
MESA INC.
By: /s/ Boone Pickens
------------------------------------
Date: March 7, 1996 (Boone Pickens,
------------- Chief Executive Officer)
----------
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ Boone Pickens
- ------------------------- Chief Executive Officer and March 7, 1996
(Boone Pickens) Chairman of the Board of
Directors
(Principal Executive Officer)
/s/ Paul W. Cain
- ------------------------- President, Chief Operating March 7, 1996
(Paul W. Cain) Officer and Director
/s/ Stephen K. Gardner
- ------------------------- Vice President and Chief March 7, 1996
(Stephen K. Gardner) Financial Officer
(Principal Financial Officer)
/s/ William D. Ballew
- ------------------------- Controller March 7, 1996
(William D. Ballew) (Principal Accounting Officer)
/s/ John S. Herrington
- ------------------------- Director March 7, 1996
(John S. Herrington)
/s/ Wales H. Madden, Jr.
- ------------------------- Director March 7, 1996
(Wales H. Madden, Jr.)
/s/ Dorn Parkinson
- ------------------------- Director March 7, 1996
(Dorn Parkinson)
/s/ Joel L. Reed
- ------------------------- Director March 7, 1996
(Joel L. Reed)
/s/ Fayez S. Sarofim
- ------------------------- Director March 7, 1996
(Fayez S. Sarofim)
/s/ Robert L. Stillwell
- ------------------------- Director March 7, 1996
(Robert L. Stillwell)
<PAGE>
CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
--------------------------------------------------------
Page in Form 10-K
-----------------
Report of Independent Public Accountants................ F-2
Consolidated Statements of Operations................... F-3
Consolidated Balance Sheets............................. F-4
Consolidated Statements of Cash Flows................... F-5
Consolidated Statements of Changes
in Stockholders' Equity............................... F-6
Notes to Consolidated Financial Statements.............. F-7
Supplemental Financial Data............................. F-8
F-1
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
----------------------------------------
To MESA Inc.:
We have audited the accompanying consolidated balance sheets of MESA Inc. (a
Texas corporation) and subsidiaries as of December 31, 1995 and 1994, and
the related consolidated statements of operations, cash flows and changes in
stockholders' equity for each of the three years in the period ended
December 31, 1995. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of MESA
Inc. and subsidiaries as of December 31, 1995 and 1994, and the results of
their operations and their cash flows for each of the three years in the
period ended December 31, 1995, in conformity with generally accepted
accounting principles.
The accompanying financial statements have been prepared assuming that the
Company will continue as a going concern. As discussed further in Note 2 to
the consolidated financial statements, the Company's current financial
forecasts indicate that cash generated by operating activities, together
with available cash and investment balances, will not be sufficient for the
Company to make all of its required debt principal and interest obligations
due in June 1996. Also, as discussed in Notes 2 and 4 to the consolidated
financial statements, certain covenants related to the Company's bank debt
and certain cross-default provisions of the Discount Notes could result in
the acceleration of approximately $656 million of long-term debt principal
(due in mid-1997 and mid-1998) to the first half of 1996. As a result,
there is substantial doubt about the Company's ability to continue as a
going concern. Management's plans in regard to these matters are also
described in Note 2 to the consolidated financial statements. The
consolidated financial statements do not include any adjustments relating to
the recoverability and classification of asset carrying amounts or the
amount and classification of liabilities that might result should the
Company be unable to continue as a going concern.
/s/ Arthur Andersen LLP
-----------------------
ARTHUR ANDERSEN LLP
Houston, Texas
March 6, 1996
F-2
<PAGE>
MESA Inc.
CONSOLIDATED STATEMENTS OF OPERATIONS
-------------------------------------
(in thousands, except per share data)
Years Ended December 31
-------------------------------
1995 1994 1993
Revenues: --------- --------- ---------
Natural gas........................... $ 129,534 $ 139,580 $ 141,798
Natural gas liquids................... 75,321 72,771 61,427
Oil and condensate.................... 19,594 7,877 12,428
Other................................. 10,510 8,509 6,551
--------- --------- ---------
234,959 228,737 222,204
--------- --------- ---------
Costs and Expenses:
Lease operating....................... 51,815 52,655 51,819
Production and other taxes............ 18,403 21,306 20,332
Exploration charges................... 6,604 5,157 2,705
General and administrative............ 26,749 28,649 25,237
Depreciation, depletion and
amortization........................ 83,423 92,287 100,099
--------- --------- ---------
186,994 200,054 200,192
--------- --------- ---------
Operating Income........................... 47,965 28,683 22,012
--------- --------- ---------
Other Income (Expense):
Interest income....................... 15,922 13,457 10,704
Interest expense...................... (148,630) (144,757) (142,002)
Gains from investments................ 18,420 6,698 3,954
Gains from collections from
Bicoastal Corporation............... 6,352 16,577 18,450
Gains on dispositions of oil
and gas properties.................. -- -- 9,600
Litigation settlement................. -- -- (42,750)
Gain from adjustment of contingency
reserve............................. -- -- 24,000
Other................................. 2,403 (4,011) (6,416)
--------- --------- ---------
(105,533) (112,036) (124,460)
--------- --------- ---------
Net Loss................................... $ (57,568) $ (83,353) $(102,448)
========= ========= =========
Net Loss Per Common Share.................. $ (.90) $ (1.42) $ (2.61)
========= ========= =========
Weighted Average Common Shares Outstanding. 64,050 58,860 39,272
========= ========= =========
(See accompanying notes to consolidated financial statements.)
F-3
<PAGE>
MESA Inc.
CONSOLIDATED BALANCE SHEETS
---------------------------
(in thousands, except share data)
December 31
----------------------
ASSETS 1995 1994
---------- ----------
Current Assets:
Cash and cash investments..................... $ 149,143 $ 143,422
Investments................................... 38,280 19,112
Accounts and notes receivable................. 44,734 38,938
Other......................................... 4,590 3,372
---------- ----------
Total current assets..................... 236,747 204,844
---------- ----------
Property, Plant and Equipment:
Oil and gas properties, wells
and equipment, using the successful
efforts method of accounting................ 1,900,163 1,867,842
Office and other.............................. 41,603 43,836
Accumulated depreciation, depletion
and amortization............................ (859,077) (781,230)
---------- ----------
1,082,689 1,130,448
---------- ----------
Other Assets:
Restricted cash of subsidiary partnership..... 57,731 61,299
Gas balancing receivable...................... 56,020 54,971
Other......................................... 31,509 32,397
---------- ----------
145,260 148,667
---------- ----------
$1,464,696 $1,483,959
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities on long-term debt.......... $ 101,413 $ 30,537
Accounts payable and accrued liabilities...... 31,068 40,468
Interest payable.............................. 60,465 18,184
---------- ----------
Total current liabilities................ 192,946 89,189
---------- ----------
Long-Term Debt..................................... 1,135,330 1,192,756
---------- ----------
Deferred Revenue................................... 17,578 21,900
---------- ----------
Other Liabilities.................................. 51,838 55,542
---------- ----------
Contingencies
Stockholders' Equity:
Preferred stock, $.01 par value, authorized
10,000,000 shares; no shares issued and
outstanding................................. -- --
Common stock, $.01 par value, authorized
100,000,000 shares; outstanding 64,050,009
and 64,050,009 shares, respectively......... 640 640
Additional paid-in capital.................... 398,965 398,965
Accumulated deficit........................... (332,601) (275,033)
---------- ----------
67,004 124,572
---------- ----------
$1,464,696 $1,483,959
========== ==========
(See accompanying notes to consolidated financial statements.)
F-4
<PAGE>
MESA Inc.
CONSOLIDATED STATEMENTS OF CASH FLOWS
-------------------------------------
(in thousands)
Years Ended December 31
-----------------------------
1995 1994 1993
-------- --------- --------
Cash Flows From Operating Activities:
Net loss................................ $(57,568) $ (83,353)$(102,448)
Adjustments to reconcile net loss
to net cash provided by
operating activities:
Depreciation, depletion and
amortization..................... 83,423 92,287 100,099
Gains on dispositions of
oil and gas properties........... -- -- (9,600)
Accreted interest on discount notes 38,957 79,352 49,160
Accrued interest exchanged for
discount notes................... -- -- 15,395
Litigation settlement.............. -- (42,750) 42,750
Gain from adjustment of
contingency reserves............. -- -- (24,000)
Decrease (increase) in gas
balancing receivables............ 1,516 (7,840) (4,942)
Decrease in deferred natural gas
revenue.......................... (4,219) (785) (3,370)
Settlement of prior year tax claims -- -- (12,931)
Natural gas hedging activities..... (9,715) 9,715 324
Sales of investments............... 48,555 18,771 39,283
Purchases of investments........... (49,003) (19,866) (34,711)
Gains from investments............. (18,420) (6,698) (3,954)
(Increase) decrease in
accounts receivable.............. (12,047) 5,934 1,986
Increase (decrease) in payables
and accrued liabilities.......... 45,243 (3,142) (15,887)
Other.............................. 2,519 6,972 (4,662)
-------- -------- --------
Net cash provided by
operating activities............. 69,241 48,597 32,492
-------- -------- --------
Cash Flows From Investing Activities:
Capital expenditures.................... (42,297) (32,590) (29,636)
Proceeds from dispositions of
oil and gas properties................ -- -- 26,118
Collection of notes receivable.......... -- -- 47,501
Other................................... 860 (7,660) (6,461)
-------- -------- --------
Net cash provided by (used in)
investing activities............. (41,437) (40,250) 37,522
-------- -------- --------
Cash Flows From Financing Activities:
Issuance of common stock................ -- 93,067 --
Repayments of long-term debt............ (25,507) (175,107) (80,102)
Long-term borrowings.................... -- 77,754 --
Debt issuance costs..................... -- -- (9,651)
Other................................... 3,424 652 1,251
-------- -------- --------
Net cash used in
financing activities............. (22,083) (3,634) (88,502)
-------- -------- --------
Net Increase (Decrease) in Cash and
Cash Investments........................... 5,721 4,713 (18,488)
Cash and Cash Investments
at Beginning of Year....................... 143,422 138,709 157,197
-------- -------- --------
Cash and Cash Investments at End of Year..... $149,143 $143,422 $138,709
======== ======== ========
(See accompanying notes to consolidated financial statements.)
F-5
<PAGE>
MESA Inc.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
----------------------------------------------------------
(in thousands)
Common Stock Additional
-------------- Paid-in Accumulated
Shares Amount Capital Deficit
------ ------ ---------- -----------
Balance, December 31, 1992.......... 38,571 $386 $273,198 $ (89,232)
Net loss....................... -- -- -- (102,448)
Common stock issued for
0% convertible notes......... 7,523 75 29,239 --
Common stock issued for the
partial conversion of
the General Partner
minority interest............ 417 4 907 --
------ ---- -------- ---------
Balance, December 31, 1993.......... 46,511 465 303,344 (191,680)
Net loss....................... -- -- -- (83,353)
Common stock issued for the
conversion of the remaining
General Partner minority
interest..................... 1,251 13 2,716 --
Common stock issued in
secondary public offering.... 16,288 162 92,905 --
------ ---- -------- ---------
Balance, December 31, 1994.......... 64,050 640 398,965 (275,033)
Net loss....................... -- -- -- (57,568)
------ ---- -------- ---------
Balance, December 31, 1995.......... 64,050 $640 $398,965 $(332,601)
====== ==== ======== =========
(See accompanying notes to consolidated financial statements.)
F-6
<PAGE>
MESA Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
(1) Organization and Summary of Significant Accounting Policies
===========================================================
MESA Inc., a Texas corporation, was formed in 1991 in connection with a
transaction (the "Corporate Conversion") which reorganized the business of
Mesa Limited Partnership (the "Partnership"). The Partnership was formed in
1985 to succeed to the business of Mesa Petroleum Co. ("Original Mesa").
Unless the context otherwise requires, as used herein the term "Company"
refers to MESA Inc. and its subsidiaries taken as a whole and includes its
predecessors.
The Company is primarily in the business of exploring for, developing,
producing, processing and selling natural gas and oil in the United States.
Over 60% of the Company's annual equivalent production is natural gas and
the balance is principally natural gas liquids. The Company's primary
producing areas are the Hugoton field of southwest Kansas, the West
Panhandle field of Texas and the Gulf of Mexico offshore Texas and
Louisiana. Production from the Company's properties has access to a
substantial portion of the major metropolitan markets in the United States,
primarily in the midwest and northeast, through numerous pipelines and other
purchasers.
The preparation of the consolidated financial statements of the Company
in conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the consolidated financial statements and the
reported amounts of revenues and expenses during the reporting period.
Actual results could differ from the estimates.
Principles of Consolidation
- ---------------------------
The Company owns and operates its oil and gas properties and other
assets through various direct and indirect subsidiaries. Pursuant to the
Corporate Conversion, the Company obtained a 95.86% limited partnership
interest and Boone Pickens (the "General Partner") obtained a 4.14% general
partner interest in three direct subsidiary partnerships. The general
partner interest was convertible into a total of 1,667,560 shares of common
stock of the Company. On December 31, 1993, the General Partner converted
approximately one-fourth of his general partner interests into common stock.
In early 1994 the Company effected a series of merger transactions which
resulted in the conversion of each of its direct subsidiary partnerships to
corporate form (see Note 13). Pursuant to these mergers, the remaining
general partner interests in the Company's subsidiary partnerships held
directly or indirectly by the General Partner were converted into common
stock, thereby eliminating the minority interest.
The accompanying consolidated financial statements reflect the
consolidated accounts of the Company and its subsidiaries after elimination
of intercompany transactions.
Certain reclassifications have been made to amounts reported in
previous years to conform to 1995 presentation.
Statements of Cash Flows
- ------------------------
For purposes of the statements of cash flows, the Company classifies
all cash investments with original maturities of three months or less as
cash and cash investments.
Investments
- -----------
On January 1, 1994, the Company adopted Statement of Financial
Accounting Standards ("SFAS") No. 115, "Accounting for Certain Investments
in Debt and Equity Securities," which addresses the accounting and reporting
for investments in equity securities that have readily determinable fair
values and for all investments in debt securities. The Company's portfolio
of securities is classified as "trading securities" under the provisions of
SFAS No. 115 and is reported at fair value, with unrealized gains and losses
included in net income (loss) for the current period. The cost of
securities sold is determined on the first-in, first-out basis. Prior to
January 1, 1994, investments in marketable securities were stated at the
lower of cost or market. The adoption of SFAS No. 115 did not have a
material effect on the financial position or results of operations of the
Company.
The Company enters into various energy futures contracts including New
York Mercantile Exchange ("NYMEX") futures contracts, commodity price swaps
and options which are not intended to be hedges of future natural gas or
crude oil production. Investments in such contracts are adjusted to market
prices at the end of each reporting period and gains and losses are included
in gains from investments in the statements of operations.
Oil and Gas Properties
- ----------------------
Under the successful efforts method of accounting, all costs of
acquiring unproved oil and gas properties and drilling and equipping
exploratory wells are capitalized pending determination of whether the
properties have proved reserves. If an exploratory well is determined to be
nonproductive, the drilling and equipment costs of the well are expensed at
that time. All development drilling and equipment costs are capitalized.
Capitalized costs of proved properties and estimated future dismantlement
and abandonment costs are amortized on a property-by-property basis using
the unit-of-production method whereby the ratio of annual production to
beginning of period proved oil and gas reserves is applied to the remaining
net book value of such properties. Oil and gas reserve quantities represent
estimates only and there are numerous uncertainties inherent in the
estimation process. Actual future production may be materially different
from amounts estimated and such differences could materially affect future
amortization of proved properties. Geological and geophysical costs and
delay rentals are expensed as incurred.
Unproved properties are periodically assessed for impairment of value
and a loss is recognized at the time of impairment. The aggregate carrying
value of proved properties is periodically compared with the undiscounted
future net cash flows from proved reserves, determined in accordance with
Securities and Exchange Commission (the "Commission") regulations, and a
loss is recognized if permanent impairment of value is determined to exist.
A loss is recognized on proved properties expected to be sold in the event
that carrying value exceeds expected sales proceeds.
In March 1995 the Financial Accounting Standards Board (the "FASB")
issued SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of," which establishes accounting
standards for the impairment of long-lived assets, certain identifiable
intangibles and goodwill. SFAS No. 121 requires a review for impairment
whenever circumstances indicate that the carrying amount of an asset may not
be recoverable. In performing the review for recoverability, the Company
would estimate future cash flows (undiscounted and without interest charges)
expected to result from use of an asset and its eventual disposition.
Impairment is recognized only if the carrying amount of an asset is greater
than the expected future cash flows. The amount of impairment is based on
the fair value of the asset. Under SFAS No. 121, each field is individually
evaluated for impairment. The Company will adopt the provisions of SFAS No.
121 in 1996 and has estimated that impairment of approximately $10 to $12
million will be charged to operations in the first quarter of 1996. Such
impairment relates primarily to a Gulf Coast oil and gas property.
Net Loss Per Common Share
- -------------------------
The computations of net loss per common share are based on the weighted
average number of common shares outstanding during each period.
Fair Value of Financial Instruments
- -----------------------------------
The Company's financial instruments consist of cash, marketable
securities, commodity price swaps, options, short-term trade receivables and
payables, restricted cash, notes receivable, and long-term debt. The
carrying values of cash, marketable securities, notes receivable, short-term
trade receivables and payables, and restricted cash approximate fair value.
The carrying values of the commodity price swaps and options represent their
required cash deposits plus or minus unrealized gains and losses (see Note
3). The fair value of long-term debt is estimated based on the market
prices for the Company's publicly traded debt and on current rates available
for similar debt with similar maturities and security for the Company's
remaining debt (see Note 4).
Gas Revenues
- ------------
The Company recognizes its ownership interest in natural gas production
as revenue. Actual production quantities sold by the Company may be
different than its ownership share of production in a given period. If the
Company's sales exceed its ownership share of production, the differences
are recorded as deferred revenue. Gas balancing receivables are recorded
when the Company's ownership share of production exceeds sales. The Company
also accrues production expenses related to its ownership share of
production. At December 31, 1995, the Company had produced and sold a
cumulative net 21.9 billion cubic feet ("Bcf") of natural gas less than its
ownership share of production and had recorded gas balancing receivables,
net of deferred revenues, of approximately $38.8 million. Substantially all
of the Company's gas balancing receivables and deferred revenue are
classified as long-term.
The Company periodically enters into NYMEX natural gas futures
contracts as a hedge against natural gas price fluctuations. Gains or
losses on such futures contracts are deferred and recognized as natural gas
revenue when the hedged production occurs. The Company recognized net gains
of $12.7 million and $895,000 in 1995 and 1994, respectively, and a net loss
of $324,000 in 1993 related to hedging activities.
Taxes
- -----
The Company provides for income taxes using the asset and liability
method under which deferred income taxes are recognized for the tax
consequences of "temporary differences" by applying enacted statutory tax
rates applicable to future years to differences between the financial
statement carrying amounts and the tax bases of existing assets and
liabilities. The effect on deferred taxes of a change in tax laws or tax
rates is recognized in income in the period that includes the enactment
date.
(2) Resources and Liquidity
=======================
Long-term Debt and Cash Flows
- -----------------------------
The Company is highly leveraged with over $1.2 billion of long-term
debt, including current maturities. The major components of the Company's
debt are (1) $504.7 million of secured notes due in installments through
2012 at Hugoton Capital Limited Partnership ("HCLP"), an indirect, wholly
owned subsidiary, (2) $61.1 million (plus $11.4 million in letter of credit
obligations) outstanding under a bank credit facility, due in installments
through 1997, with the majority of such debt due on June 23, 1997, (3) $39.7
million of unsecured discount notes due on June 30, 1996, and (4) $617.4
million of secured discount notes due on June 30, 1998. Both the secured
and unsecured discount notes are subordinate to the bank credit facility.
See Note 4 for a complete description of the Company's long-term debt.
The Company is required to make significant principal and interest
payments on its debt during the first six months of 1996. Including the $42
million of interest paid on its discount notes on January 2, 1996, the
Company is required to make $123.5 million of principal and interest
payments related to its discount notes and $22.5 million of principal
payments related to its bank credit facility by June 30, 1996.
The Company's bank credit facility contains a covenant requiring the
Company to maintain tangible adjusted equity, as defined, of at least $50
million. At December 31, 1995, tangible adjusted equity was $64.7 million.
Assuming no changes in its capital structure and no significant transactions
are completed, the Company expects to continue to report substantial net
losses and expects its tangible adjusted equity to fall below $50 million in
the first half of 1996. If and when the Company determines that tangible
adjusted equity is below $50 million, an Event of Default, as defined, would
occur under the bank credit facility and the bank would have the right to
accelerate the payment of all outstanding principal and require cash
collateralization of letters of credit. An Event of Default under the bank
credit facility would cause a cross default under the Company's secured and
unsecured discount note indentures unless and until the bank credit facility
default were cured or waived or the debt under the bank credit facility were
repaid or otherwise discharged. The Events of Default, if they occur and
are not waived, could result in acceleration of approximately $656 million
of long-term debt principal due in mid-1997 and mid-1998 to the first half
of 1996. Pursuant to the subordination provisions of the discount note
indentures, the Company would be prohibited from making any payments on such
notes for specified periods upon and during the continuance of any Event of
Default under the bank credit facility.
The assets and cash flows of HCLP that are subject to the mortgage
securing HCLP's debt are dedicated to service HCLP's debt and are not
available to pay creditors of the Company or its subsidiaries other than
HCLP.
The Company's current financial forecasts indicate, assuming no changes
in its capital structure and no significant transactions are completed, that
cash generated by operating activities, together with available cash and
investment balances will not be sufficient to make all of its required debt
principal and interest obligations due in June 1996. If amounts outstanding
under the Credit Agreement were to be accelerated in the first half of 1996,
the Company would expect to have sufficient cash to meet the Credit
Agreement obligations and cure an Event of Default under the Credit
Agreement and avoid, at that time, cross defaults under the terms of its
Discount Note indentures. However, such a payment would substantially
deplete the Company's remaining cash and investments balances. The Company
will make decisions regarding such payments on its debt as they come due,
taking into account the status at that time of the Rainwater transaction
discussed below.
Exploration of Strategic Alternatives/
Proposed Transaction With Rainwater
--------------------------------------
In an effort to address its liquidity issues and to position the
Company for expansion through exploration and development, in December 1994
the Company announced its intent to sell all or a portion of its interests
in the Hugoton field. In the first quarter of 1995 the Company began an
auction process to sell such properties. The Company's Board of Directors
(the "Board") concluded the auction process in the second quarter of 1995
after no acceptable bids were received for the Hugoton properties.
On July 6, 1995, the Board approved and implemented a proposal
solicitation process which expanded its exploration of strategic
alternatives to include consideration of the sale of the Company, a stock-
for-stock merger, joint ventures, asset sales, equity infusions, and
refinancing transactions. The Company engaged an independent financial
advisor to assist in these efforts and to solicit proposals on its behalf.
The proposal solicitation process commenced in August 1995 and the Company
received proposals beginning on November 20, 1995.
On February 28, 1996, the Company signed a letter of intent with
Rainwater, Inc. ("Rainwater"), an independent investment company owned by
Ft. Worth, Texas, investor Richard Rainwater, to raise $265 million of
equity in connection with a refinancing of the Company's debt. Pursuant to
the terms of the letter of intent, Rainwater will purchase in a private
placement approximately 58.8 million shares of a new class of convertible
preferred stock and the Company will offer approximately 58.4 million shares
of convertible preferred stock to the Company stockholders in a rights
offering (the "Rights Offering"). Rainwater will provide a standby
commitment to purchase any shares of preferred stock not subscribed to in
the Rights Offering. Rights will be distributed to common stockholders on a
pro rata basis. The rights will allow the stockholder to purchase, in
respect of each share of common stock, approximately .91 shares of preferred
stock at $2.26 per share, the same per share price at which Rainwater will
purchase preferred shares. The rights will be transferrable and holders of
the rights will be offered over-subscription privileges for shares not
purchased by other rights holders.
Each preferred share will be convertible into one share of the Company
common stock at any time prior to mandatory redemption in 2006. An annual
8% pay-in-kind dividend will be paid on the preferred shares during the
first four years following issuance. Thereafter, the 8% dividend may, at
the option of the Company, be paid in cash or additional shares depending on
whether certain financial tests are met.
The preferred stock will represent 63.6% of the fully diluted common
shares at the time of issuance and 70.6% after the mandatory four-year pay-
in-kind period, assuming no other stock issuance by the Company. The
preferred stock will have a liquidation price equal to the purchase price.
The preferred shares purchased in the Rights Offering will vote with the
common stock as a single class on all matters, except as otherwise required
by law and except for certain special voting rights for shares held by
Rainwater.
Rainwater will be entitled to elect two members of the Company's Board,
which will have seven directors. The Rainwater designees will constitute
two of the three members of a newly formed executive committee of the Board.
The executive committee will act for the whole Board on matters which by law
do not need Board authorization and will have authority over major capital
transactions, stock issuances, financing arrangements, budgeting, and other
items.
During an interim 30-day period beginning February 28, 1996, the
Company, with assistance from Rainwater, will seek commitments for new bank
loans plus assurance of availability of new subordinated debt to be issued
in conjunction with the transaction. Proceeds from the new debt, when
combined with proceeds from the newly issued equity and the Company's
available cash balances, would refinance or repay all of the Company's
existing debt.
The proposed transaction is subject to certain conditions, including
negotiation and execution of definitive agreements, arrangement of the new
debt financing, due diligence by Rainwater and the Company stockholder
approval. The parties anticipate executing definitive agreements in about
30 days. The transaction will be submitted to a vote of stockholders at a
special meeting expected to take place in June 1996. The Rights Offering
would commence promptly after that meeting. There can be no assurance that
this transaction will be completed, or if completed, what the final terms or
timing thereof will be. Nor can there be any assurance regarding the
availability or terms of any refinancing debt.
The ability of the Company to continue as a going concern is dependent
upon several factors. The successful completion of the Rainwater
transaction is expected to position the Company to operate and continue as a
going concern and to pursue its business strategies. The consolidated
financial statements of the Company do not include any adjustments
reflecting any treatment other than going concern accounting.
If the Rainwater transaction is not completed, the Company will pursue
other alternatives to address its liquidity issues and financial condition,
including other potential transactions arising from the proposal
solicitation process, the possibility of seeking to restructure its balance
sheet by negotiating with its current debt holders or seeking protection
from its creditors under the Federal Bankruptcy Code.
(3) Investments
===========
The value of investments are as follows (in thousands):
December 31
--------------------
1995 1994
------- -------
Equity securities:
Cost...................................... $10,719 $9,489
Unrealized loss........................... (162) (1,381)
NYMEX Futures Contracts:
Margin Cash............................... 17,498 1,337
Unrealized gain in hedge contracts........ -- 6,823
Unrealized gain in trading contracts...... 7,558 2,844
Commodity Price Swaps:
Margin Cash............................... 2,434 --
Unrealized loss in price swaps............ (811) --
Natural Gas Options:
Premiums.................................. 66 --
Unrealized gain in trading options........ 978 --
------- -------
Total market value........................ $38,280 $19,112
======= =======
In 1995 the Company recognized net gains of approximately $18.4 million
from its investments compared with net gains in 1994 of $6.7 million and in
1993 of $4.0 million. These gains do not include gains or losses from
natural gas futures contracts accounted for as a hedge of natural gas
production. Hedge gains or losses are included in natural gas revenue in
the period in which the hedged production occurs (see Note 1).
The net investment gains and losses recognized during a period include
both realized and unrealized gains and losses. The Company realized net
gains from investments of $12.3 million in 1995, $4.7 million in 1994, and
$2.3 million in 1993. At December 31, 1995, the Company had recognized but
not realized approximately $7.6 million of gains associated primarily with
natural gas futures. Subsequent to year end, the Company closed some of its
positions which were open on December 31, 1995. As of March 6, 1996, the
Company had closed substantially all of the positions open at December 31,
1995, at a realized loss of $156,000. Positions which were open at December
31, 1995, and remain open had unrealized gains of $1.7 million at March 6,
1996.
In 1995 the Company invested in certain over-the-counter commodity
price swap agreements for trading purposes. The Company is required to make
payments to (or receive payments from) a counter party based on the
differential between a fixed and a variable price for specified natural gas
volumes. The Company's agreements expire on the last day of trading for
April, May and June 1996 natural gas futures contracts as determined by the
NYMEX. The Company is the fixed price payor on a notional quantity of 10.1
million British thermal units of natural gas with a fair value of $18.3
million at December 31, 1995. The average fair value of such commodity
price swaps during 1995 was $18.4 million. In 1995 the Company also entered
into over-the-counter natural gas futures call and put options contracts.
At December 31, 1995, the open quantity of options was 1,800 contracts (each
contract represents 10,000 MMBtu of natural gas) with a fair value of $1.0
million. The average fair value of such option contracts during 1995 was
$.4 million. The counter party to these instruments is a credit-worthy
financial institution which is a recognized market-maker. The Company
believes the risk of incurring losses related to credit risk of the counter
party is remote.
(4) Long-term Debt
==============
Long-term debt and current maturities are as follows (in thousands):
December 31
------------------------
1995 1994
---------- ----------
HCLP Secured Notes.......................... $ 504,674 $ 520,180
Credit Agreement............................ 61,131 71,131
12-3/4% secured discount notes.............. 618,518 581,942
12-3/4% unsecured discount notes............ 39,725 37,345
13-1/2% subordinated notes.................. 7,390 7,390
Other....................................... 5,305 5,305
---------- ----------
1,236,743 1,223,293
Current maturities.......................... (101,413) (30,537)
---------- ----------
Long-term debt.............................. $1,135,330 $1,192,756
========== ==========
HCLP Secured Notes
- ------------------
In 1991 HCLP issued $616 million of secured notes (the "HCLP Secured
Notes") in a private placement with a group of institutional lenders. The
issuance also funded a $66 million restricted cash balance within HCLP,
which is available to supplement cash flows from the HCLP properties in the
event such cash flows are not sufficient to fund principal and interest
payments on the HCLP Secured Notes when due. As the HCLP Secured Notes are
repaid, the required restricted cash balance is reduced. HCLP holds
substantially all of the Company's Hugoton field natural gas properties.
The HCLP Secured Notes were issued in 15 series and have final stated
maturities extending through 2012 but can be retired earlier. The HCLP
Secured Notes outstanding at December 31, 1995, bear interest at fixed rates
ranging from 8.80% to 11.30% per annum (weighted average 10.31%). Principal
and interest payments are made semiannually. Provisions in the HCLP Secured
Note agreements require interest rate premiums to be paid to the noteholders
in the event that the HCLP Secured Notes are repaid more rapidly or slowly
than under the initial scheduled amortization. Beginning in August 1994,
HCLP elected to make principal payments on the HCLP Secured Notes based on
actual production, rather than according to the initial scheduled
amortization. As a result, interest rate premiums at a rate of 1.5% per
annum will be applied to those principal amounts not paid according to the
initial scheduled amortization and .35% per annum will be applied to the
remaining notes. Such premiums have increased the effective weighted
average interest rate payable on the remaining HCLP Secured Notes
outstanding to 10.79% per annum at December 31, 1995.
The HCLP Secured Note agreements contain various covenants which, among
other things, limit HCLP's ability to sell or acquire oil and gas property
interests, incur additional indebtedness, make unscheduled capital
expenditures, make distributions of property or funds subject to the
mortgage, or enter into certain types of long-term contracts or forward
sales of production. The agreements also require HCLP to maintain separate
existence from the Company and its other subsidiaries. The assets of HCLP
that are subject to the mortgage securing the HCLP Secured Notes are
dedicated to service HCLP's debt and are not available to pay creditors of
the Company or its subsidiaries other than HCLP. Any cash not subject to
the mortgage is available for distribution to the Company's subsidiaries
which own HCLP's equity.
The HCLP Secured Note agreements also contain a provision which
requires calculation and payment of premiums on early retirement of the HCLP
Secured Notes. The actual premiums due in the event of a redemption of the
HCLP Secured Notes will depend on prevailing interest rates at the date of
redemption and the amount of debt redeemed. In the aggregate, such premiums
would have totaled $79 million as of December 31, 1995.
Revenues received from production from HCLP's Hugoton properties are
deposited in a collection account maintained by a collateral agent (the
"Collateral Agent"). The Collateral Agent releases or reserves funds, as
appropriate, for the payment of royalties, taxes, operating costs, capital
expenditures and principal and interest on the HCLP Secured Notes. Only
after all required payments have been made may any remaining funds held by
the Collateral Agent be released from the mortgage.
By April 29, 1996, HCLP is required to obtain a reserve report as of
December 31, 1995, covering its Hugoton field properties prepared by an
independent engineering consultant. HCLP is required to compare the reserve
quantities in such reserve report to the initial reserve quantities set
forth in the HCLP Secured Note agreements, adjusted for production. If the
quantities in such reserve report are less than the adjusted initial
quantities, a Deficit Reserve Amount ("DRA"), as defined, is determined to
exist. To the extent a DRA exists, the Collateral Agent is required to
retain additional funds in the collection account subject to the mortgage
for the repayment of the HCLP Secured Notes. The Company is not obligated to
fund any principal payments at HCLP from sources other than HCLP's Hugoton
field properties. The independent reserve report has not been completed, but
HCLP has received preliminary indications that the independent engineers'
estimates of reserve quantities related to the Hugoton field properties will
reflect a downward revision from previous years. Although HCLP has not
determined whether a DRA will result from such downward revisions,
preliminary estimates indicate that a DRA, if any, will not be material.
The restricted cash balance and cash held by the Collateral Agent for
payment of interest and principal on the HCLP Secured Notes are invested by
the Collateral Agent under the terms of a guaranteed investment contract
(the "GIC") with Morgan Guaranty Trust Co. of New York ("Morgan"). Morgan
was paid $13.9 million at the date of issuance of the HCLP Secured Notes to
guarantee that funds invested under the GIC would earn an interest rate
equivalent to the weighted average coupon rate on the outstanding principal
balance of the HCLP Secured Notes (10.31% at December 31, 1995). A portion
of this amount may be refunded if the HCLP Secured Notes are repaid earlier
than if HCLP had produced according to its scheduled production, depending
primarily on prevailing interest rates at that time.
HCLP's cash balances were as follows (in thousands):
December 31
----------------
1995 1994
------- -------
Subject to the mortgage.............................. $40,163 $48,087
Not subject to the mortgage.......................... 7,450 1,551
------- -------
Cash included in current assets...................... $47,613 $49,638
======= =======
Restricted cash included in noncurrent assets........ $57,731 $61,299
======= =======
Refundable GIC fee included in noncurrent assets..... $ 9,010 $10,295
======= =======
Mesa Operating Co. ("MOC"), a Company subsidiary which owns 99% of the
limited partnership interests of HCLP, is party to a services agreement with
HCLP. MOC provides services necessary to operate the Hugoton field
properties and market production therefrom, processes remittances of
production revenues and performs certain other administrative functions in
exchange for a services fee. The fee totaled approximately $13.2 million in
1995, $12.8 million in 1994, and $11.4 million in 1993.
Credit Agreement
- ----------------
As of December 31, 1995, the Company had outstanding borrowings of
approximately $61.1 million and letter of credit obligations of $11.4
million under its $82.5 million bank credit facility, as amended (the
"Credit Agreement"). The Credit Agreement requires principal payments of
$22.5 million in the first half of 1996 with the remainder due in June 1997
(including cash collateralization of letters of credit outstanding at that
time).
The rate of interest payable on borrowings under the amended Credit
Agreement is the lesser of the Eurodollar rate plus 2-1/2% or the prime rate
plus 1/2%. Obligations under the Credit Agreement are secured by a first
lien on the Company's West Panhandle field properties, the Company's equity
interest in MOC and a 76% limited partner interest in HCLP.
The amended Credit Agreement requires the Company to maintain tangible
adjusted equity, as defined, of at least $50 million and available cash, as
defined, of at least $32.5 million. At December 31, 1995, the Company's
tangible adjusted equity, as defined, was approximately $64.7 million and
available cash, as defined, was $139.5 million. See Note 2 for discussion of
the tangible adjusted equity covenant and its potential effect on the
Company's liquidity.
The Credit Agreement also restricts, among other things, the Company's
ability to incur additional indebtedness, create liens, pay dividends,
acquire stock or make investments, loans and advances.
Discount Notes
- --------------
In conjunction with a debt exchange transaction consummated on August
26, 1993, (the "Debt Exchange"), the Company issued approximately $435.5
million initial accreted value, as defined, of 12-3/4% secured discount
notes due June 30, 1998 and $136.9 million initial accreted value, as
defined, of 12-3/4% unsecured discount notes due June 30, 1996 (together,
the "Discount Notes") in exchange for $293.7 million aggregate principal
amount of 12% subordinated notes and $292.6 million aggregate principal
amount of 13-1/2% subordinated notes (together with the $28.6 million of
accrued interest claims thereon). The Company also issued $29.3 million
principal amount of 0% convertible notes due June 30, 1998, which were
converted into approximately 7.5 million shares of common stock by the end
of 1993. The Discount Notes, which rank pari passu with each other, are
senior in right of payment to the remaining 13-1/2% subordinated notes due
1999 and subordinate to all permitted first lien debt, as defined, including
obligations under the Credit Agreement.
On March 2, 1994, the Company issued $48.2 million face amount of
additional 12-3/4% secured discount notes due June 30, 1998. The proceeds
of $42.8 million were used to pay the settlement amount arising from the
1994 settlement of a lawsuit with Unocal Corporation ("Unocal"). The
additional indebtedness incurred to settle the Unocal lawsuit was
specifically permitted under the terms of the indentures governing the
Discount Notes and under the Credit Agreement. (See Note 9 for additional
discussion of the Unocal litigation.)
The Discount Notes did not accrue interest through June 30, 1995;
however, the accreted value, as defined, of both series increased at a rate
of 12-3/4% per year, compounded semiannually, until June 30, 1995.
Beginning July 1, 1995, each series began to accrue interest at an annual
rate of 12-3/4%, payable in cash semiannually in arrears, with the first
payment due on December 31, 1995.
In the second quarter of 1994 the Company completed a public offering
in which 16.3 million shares of the Company's common stock were sold for net
proceeds of $93 million ($6 per share) (the "Equity Offering"). The Company
used approximately $87 million of the proceeds to redeem or repurchase $87
million accreted value ($99.1 million face amount at maturity) of 12-3/4%
unsecured discount notes which were due in 1996.
In the fourth quarter of 1994 the Company used proceeds from increased
borrowings under its amended Credit Agreement to redeem $37.6 million
accreted value ($40.0 million face amount at maturity) of 12-3/4% unsecured
discount notes which were due in 1996.
The 12-3/4% secured discount notes are secured by second liens on the
Company's West Panhandle field properties and a 76% limited partner interest
in HCLP, both of which also secure obligations under the Credit Agreement.
The Company's right to maintain first lien debt, as defined, is limited by
the terms of the Discount Notes to $82.5 million.
See Note 2 for a discussion of certain cross-default provisions in the
Discount Note indentures which could become effective if the Company
defaults under the terms of the tangible adjusted equity covenant of the
Credit Agreement.
The indentures governing the Discount Notes restrict, among other
things, the Company's ability to incur additional indebtedness, pay
dividends, acquire stock or make investments, loans and advances.
Subordinated Notes
- ------------------
The 13-1/2% subordinated notes are unsecured and mature in 1999.
Interest on these notes is payable semiannually in cash.
Interest and Maturities
- -----------------------
The aggregate interest payments, net of amounts capitalized, made
during 1995, 1994, and 1993 were $63.8 million, $62.1 million and $86.5
million, respectively. In addition, on January 2, 1996, according to terms
of the Discount Notes, the Company made a $42 million interest payment
related to its Discount Notes which was due December 31, 1995. Payment of
approximately $39.0 million, $70.6 million and $64.6 million of interest
incurred during 1995, 1994 and 1993, respectively, has been deferred under
the terms of the Debt Exchange until the repayment dates of the Discount
Notes. Such interest is included in interest expense in the 1995, 1994 and
1993 consolidated statements of operations.
The scheduled principal repayments on long-term debt for the next five
years are as follows (in millions):
1996 1997 1998 1999 2000
------ ------ ------ ------ ------
HCLP Secured Notes(a).............. $ 33.9 $ 33.3 $ 36.1 $ 37.1 $ 36.0
Credit Agreement(b)(c)............. 22.5 38.6 -- -- --
12-3/4% secured discount notes(d).. -- -- 617.4 -- --
12-3/4% unsecured discount notes(d) 39.7 -- -- -- --
13-1/2% subordinated notes......... -- -- -- 7.4 --
Other.............................. 5.3 -- -- -- --
------ ------ ------ ------ ------
Total......................... $101.4 $ 71.9 $653.5 $ 44.5 $ 36.0
====== ====== ====== ====== ======
- ----------
(a) Principal payment requirements could be greater, in the
aggregate, in 1996 through 1998 if a DRA is determined to exist.
(b) Excludes approximately $11.4 million in letter of credit
obligations currently outstanding and required to be cash
collateralized in June 1997.
(c) Maturities may be accelerated if tangible adjusted equity falls
below $50 million. (See Note 2).
(d) Maturities may be accelerated if an Event of Default occurs and
continues under the Credit Agreement. (See Note 2).
Fair Value of Long-term Debt
- ----------------------------
The following is a summary of estimated fair value of the Company's
long-term debt as of the years ended (in thousands):
1995 1994
------------------ ------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- -------- -------- --------
HCLP Secured Notes.............. $504,674 $568,641 $520,180 $535,135
Credit Agreement................ 61,131 61,131 71,131 71,131
12-3/4% secured discount notes.. 618,518 541,905 581,942 528,688
12-3/4% unsecured discount notes 39,725 35,262 37,345 37,591
13-1/2% subordinated notes...... 7,390 7,390 7,390 7,390
The fair value of long-term debt is estimated based on the market
prices for the Company's publicly traded debt and on current rates available
for similar debt with similar maturities and security for the Company's
remaining debt. Based on the current financial condition of the Company,
there is no assurance that the Company could obtain borrowings under long-
term debt agreements with terms similar to those described above and receive
proceeds approximating the estimated fair values.
(5) Income Taxes
============
The Company provides for income taxes using the asset and liability
method under which deferred tax assets and liabilities are recognized by
applying the enacted statutory tax rates applicable to future years to
temporary differences between the financial statement and tax bases of
existing assets and liabilities. The tax basis of the Company's
consolidated net assets is greater than the financial basis of those net
assets; therefore a net deferred tax asset has been recorded. However, due
to the Company's history of net operating losses and its current financial
condition, a valuation allowance has been recorded which offsets the entire
net deferred tax asset. A summary of the Company's net deferred tax asset
is as follows (in millions):
December 31
---------------
1995 1994
------ ------
Deferred tax asset................................... $ 261 $ 240
Deferred tax liability............................... -- --
Valuation allowance.................................. (261) (240)
------ ------
Net deferred tax asset.......................... $ -- $ --
====== ======
The principal components of the Company's net deferred tax asset
(utilizing a 39% combined federal and state income tax rate) and the
valuation allowance are as follows (in millions):
December 31
---------------
1995 1994
------ ------
Tax basis of oil and gas properties in
excess of financial basis.......................... $ 75 $ 80
Regular tax net operating loss carryforward.......... 184 156
Other, net........................................... 2 4
Valuation allowance.................................. (261) (240)
------ ------
Net deferred tax asset.......................... $ -- $ --
====== ======
At December 31, 1995, the Company had a regular tax net operating loss
carryforward of approximately $470 million. Additionally, the Company had
an alterative minimum tax loss carryforward available to offset future
alternative minimum taxable income of approximately $450 million. If not
used, these carryforwards will expire between 2007 and 2010.
The Internal Revenue Service Code of 1986 (the "Code") contains
numerous provisions which restrict or limit the use of corporate tax
attributes in conjunction with corporate acquisitions, dispositions, and
reorganizations. Included among these restrictive provisions is Code
Section 382 which, in general, limits the utilization of net operating loss
carryovers subsequent to a substantial change (generally more than 50%) in
corporate stock ownership. The Section 382 ownership change (as defined for
tax purposes) is considered on a cumulative basis over a specified time
period, normally three years. Successful completion of the Rainwater
transaction (see Note 2) is expected to result in a Section 382 ownership
change which will limit the utilization of the Company's tax carryforwards
prior to their expiration.
The Company assumed from the Partnership any tax liabilities or refunds
which may arise as a result of any changes to Original Mesa's taxable income
or loss for open tax years. During 1993, the Internal Revenue Service (the
"IRS") completed two field examinations of the tax returns filed by Original
Mesa for the tax years 1984 through 1987. In December 1993 the Company made
a payment to the IRS of approximately $13 million, which payment includes
interest, in full settlement of all claims for these years. The Company was
fully reserved for the additional tax assessment relating to the tax years
1984 through 1987. As of January 1, 1995, there are no remaining open tax
years for Original Mesa for federal income tax purposes.
(6) Property Sales
==============
In April 1993 the Company sold a portion of its Rocky Mountain area
properties for approximately $7.1 million, after adjustments, and recorded a
gain on the sale of approximately $4.1 million. The Company also retained a
reversionary interest in the properties under which the Company will receive
a 50% net profits interest in the properties after the purchaser has
recovered its investment and certain other costs and expenses.
In June 1993 the Company sold its interest in the deep portion of the
Hugoton field not owned by HCLP for approximately $19.0 million, after
adjustments, and recorded a gain on the sale of approximately $5.5 million.
(7) Stockholders' Equity
====================
At December 31, 1995, the Company had outstanding 64.1 million shares
of common stock. In 1993 the Company issued 7.5 million shares of common
stock in conjunction with the Debt Exchange (see Note 4). In late 1993 and
1994 the Company issued a total of approximately 1.7 million shares of
common stock in exchange for the General Partner's 4.14% interest in the
subsidiary partnerships of the Company (see Note 1). In 1994 the Company
completed the Equity Offering which resulted in the issuance of an
additional 16.3 million shares of common stock. Proceeds from the Equity
Offering increased stockholders' equity by approximately $93 million and
were used to reduce long-term debt (see Note 4).
The Company has authorized 10 million shares of preferred stock. No
shares of preferred stock have been issued as of December 31, 1995.
(8) Notes Receivable
================
Prior to 1992 the Company had notes receivable totaling $68 million,
exclusive of interest, from Bicoastal Corporation ("Bicoastal") which was in
bankruptcy. Because of the uncertainty of collection, the Company did not
record interest on these notes. A plan of reorganization for Bicoastal was
approved by the Bankruptcy Court in September 1992. During 1992 and 1993,
the Company collected a total of approximately $74 million from Bicoastal,
representing all of the Company's principal amount of allowed claims in the
bankruptcy reorganization plan, plus an additional amount representing a
portion of its interest claims. As a result, the Company recorded gains of
$18.5 million in 1993 relating to collections in excess of the recorded
receivable. In 1995 and 1994 the Company recorded gains of $6.4 million and
$16.6 million, respectively, from additional interest claims collected from
Bicoastal.
(9) Contingencies
=============
Masterson
- ---------
In February 1992 the current lessors of an oil and gas lease (the "Gas
Lease") dated April 30, 1955, between R. B. Masterson, et al., as lessor,
and Colorado Interstate Gas Company ("CIG"), as lessee, sued CIG in Federal
District Court in Amarillo, Texas, claiming that CIG had underpaid royalties
due under the Gas Lease. The Company owns an interest in the Gas Lease. In
August 1992 CIG filed a third-party complaint against the Company for any
such royalty underpayments which may be allocable to the Company's interest
in the Gas Lease. The plaintiffs alleged that the underpayment was the
result of CIG's use of an improper gas sales price upon which to calculate
royalties and that the proper price should have been determined pursuant to
a "favored-nations" clause in a July 1, 1967, amendment to the Gas Lease
(the "Gas Lease Amendment"). The plaintiffs also sought a declaration by
the court as to the proper price to be used for calculating future
royalties.
The plaintiffs alleged royalty underpayments of approximately $500
million (including interest at 10%) covering the period from July 1, 1967,
to the present. In March 1995 the court made certain pretrial rulings that
eliminated approximately $400 million of the plaintiffs' claims (which
related to periods prior to October 1, 1989), but which also reduced a
number of the Company's defenses. The Company and CIG filed stipulations
with the court whereby the Company would have been liable for between 50%
and 60%, depending on the time period covered, of an adverse judgment
against CIG for post-February 1988 underpayments of royalties.
On March 22, 1995, a jury trial began and on May 4, 1995, the jury
returned its verdict. Among its findings, the jury determined that CIG had
underpaid royalties for the period after September 30, 1989, in the amount
of approximately $140,000. Although the plaintiffs argued that the
"favored-nations" clause entitled them to be paid for all of their gas at
the highest price voluntarily paid by CIG to any other lessor, the jury
determined that the plaintiffs were estopped from claiming that the
"favored-nations" clause provides for other than a pricing-scheme to
pricing-scheme comparison. In light of this determination, and the
plaintiffs' stipulation that a pricing-scheme to pricing-scheme comparison
would not result in any "trigger prices" or damages, defendants asked the
court for a judgment that plaintiffs take nothing. The court, on June 7,
1995, entered final judgment that plaintiffs recover no monetary damages.
The Company cannot predict whether the plaintiffs will appeal. However,
based on the jury verdict and final judgment, the Company does not expect
the ultimate resolution of this lawsuit to have a material adverse effect on
its financial position or results of operations.
Lease Termination
- -----------------
In 1991 the Company sold certain producing oil and gas properties to
Seagull Energy Company ("Seagull"). In 1994 two lawsuits were filed against
Seagull in the 100th District Court in Carson County, Texas, by certain land
and royalty owners claiming that certain of the oil and gas leases owned by
Seagull have terminated due to cessation in production and/or lack of
production in paying quantities occurring at various times from first
production through 1994. In the third quarter of 1995 Seagull filed third-
party complaints against the Company claiming breach of warranty and false
representation in connection with the sale of such properties to Seagull.
The Company believes it has several defenses to these lawsuits including a
two-year limitation on indemnification set forth in the purchase and sale
agreement.
Seagull filed a similar third-party complaint against the Company
covering a different lease in the 69th District Court in Moore County,
Texas. The Company believes it has similar defenses in this case.
The plaintiffs in the cases against Seagull are seeking to terminate
the leases. Seagull, in its complaint against the Company, is seeking
unspecified damages relating to any leases which are terminated.
The Company does not expect the resolution of this lawsuit to have a
material adverse effect on its financial position or results of operations.
Unocal
- ------
The Company was subject to a lawsuit relating to a 1985 investment in
Unocal which asserted that certain profits allegedly realized by the Company
and other defendants upon the disposition of Unocal common stock in 1985
were recoverable by Unocal pursuant to Section 16(b) of the Securities
Exchange Act of 1934. On January 11, 1994, the Company and other defendants
entered into a settlement agreement (the "Settlement Agreement") whereby
they agreed to pay Unocal an aggregate of $47.5 million, of which $42.75
million was to be paid by the Company and $4.75 million by the other
defendants. The Settlement Agreement was approved by the court on February
28, 1994. The Company funded its share of the settlement amount with
proceeds from issuance of additional long-term debt. (See Note 4 for
discussion of the issuance of the additional long-term debt.) As a result
of the settlement, the Company recognized a $42.8 million loss in the fourth
quarter of 1993.
Other
- -----
The Company is also a defendant in other lawsuits and has assumed
liabilities relating to Original Mesa and the Partnership. The Company does
not expect the resolution of these other matters to have a material adverse
effect on its financial position or results of operations.
The Company assumed certain litigation and tax-related obligations from
Original Mesa and the Partnership and also recorded certain contingent
liabilities relating to various matters, including litigation, office space
leases and retirement benefit obligations, in conjunction with the 1986
acquisition of Pioneer Corporation ("Pioneer") and the 1988 acquisition of
Tenneco Inc.'s midcontinent division. During the fourth quarter of 1993,
the Company settled certain claims with the IRS (see Note 5) and resolved or
revalued certain other contingent liabilities to reflect actual or estimated
liabilities. The Company had previously reserved for the IRS claims and
certain other contingencies in excess of the actual or estimated
liabilities. As a result, the Company recorded a net gain of $24 million in
the fourth quarter of 1993.
(10) Employee Benefit Plans
======================
Retirement Plans
- ----------------
The Company maintains two defined contribution retirement plans for the
benefit of its employees. The Company expensed $.8 million in 1995, $3.3
million in 1994, and $3.2 million in 1993 in connection with these plans.
Option Plan
- -----------
In December 1991 the stockholders of the Company approved the 1991
Stock Option Plan of the Company (the "Option Plan"), which authorized the
grant of options to purchase up to two million shares of common stock to
officers and key employees. In May 1994 the stockholders of the Company
approved an amendment to the Option Plan which increased the number of
shares of common stock authorized from two million to four million. The
exercise price for each share of common stock placed under option cannot be
less than 100% of the fair market value of the common stock on the date the
option is granted. Upon exercise, the grantee may elect to receive either
shares of common stock or, at the discretion of the Option Committee of the
Board of Directors, cash or certain combinations of stock and cash in an
amount equal to the excess of the fair market value of the common stock at
the time of exercise over the exercise price. At December 31, 1995, the
following stock options were outstanding:
Number of
Options
---------
Outstanding at December 31, 1994............................ 2,926,460
Granted................................................ 20,000
Exercised.............................................. --
Forfeited.............................................. (14,070)
---------
Outstanding at December 31, 1995............................ 2,932,390
=========
The outstanding options at December 31, 1995, are detailed as follows:
Number of Date of Exercise Price
Options Grant Per Share Exercisable
--------- -------- -------------- -----------
1,126,000 .................. 01/10/92 $ 6.8125 1,126,000
134,500 .................. 10/02/92 11.6875 134,500
101,890 .................. 05/18/93 5.8125 81,512
475,000 .................. 11/10/93 7.3750 380,000
75,000 .................. 06/06/94 6.1875 41,250
1,000,000 .................. 12/01/94 4.2500 550,000
20,000 .................. 05/12/95 5.6875 6,000
--------- ---------
2,932,390 2,319,262
========= =========
Options are exercisable from the date of grant as follows: after six
months, 30%; after one year, 55%; after two years, 80%; and after three
years, 100%. At December 31, 1995, options for 1,004,890 shares were
available for grant.
In October 1995 the FASB issued SFAS No. 123, "Accounting for Stock-
Based Compensation," which establishes accounting and reporting standards
for stock-based employee compensation plans. SFAS No. 123 defines a fair
value-based method of accounting for stock options or similar equity
instruments, but allows companies to continue to measure compensation cost
using the intrinsic value-based method prescribed by Accounting Principles
Board Opinion ("APB") No. 25, "Accounting for Stock Issued to Employees."
Under the fair value-based method, compensation cost is measured at the
grant date based on the value of the award and is recognized over the
service period (generally, the vesting period). Under the intrinsic value-
based method, compensation cost is the excess, if any, of the quoted market
price of the stock at the date of grant over the exercise price.
Under the provisions of SFAS No. 123, a company may elect to measure
compensation cost associated with its stock option and similar plans as a
component of compensation expense in its statement of operations. Companies
may also elect to continue to measure compensation cost under the provisions
of APB No. 25. Companies which elect to continue measurement under APB No.
25 are required to provide pro forma disclosure in the notes to financial
statements reflecting the difference, if any, between compensation cost
included in net income and the cost if the fair value-based method were used
including effects on earnings per share. Since the inception of the Option
Plan, the Company has not recognized any compensation cost related to grants
of stock options. The disclosure requirements of this statement are
effective for financial statements for fiscal years beginning after December
15, 1995. At this time, the Company does not expect to adopt the fair
value-based method of accounting for its stock option plans and,
accordingly, adoption of this statement will have no impact on the Company's
results of operations.
Postretirement Benefits
- -----------------------
Effective January 1, 1993, the Company adopted SFAS No. 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions,"
which requires that the costs of such benefits be recorded over the periods
of employee service to which they relate. For the Company, this standard
primarily applies to postretirement medical benefits for retired and current
employees. The liability for benefits existing at the date of adoption (the
"Transition Obligation") will be amortized over the remaining life of the
retirees or 20 years, whichever is shorter.
The Company maintains two separate plans for providing postretirement
medical benefits. One plan covers the Company's retirees and current
employees (the "MESA Plan"). The other plan relates to the retirees of
Pioneer which was acquired by the Company in 1986 (the "Pioneer Plan").
Under the MESA Plan, employees who retire from the Company and who have had
at least ten years of service with the Company after attaining age 45 are
eligible for postretirement health care benefits. These benefits may be
subject to deductibles, copayment provisions, retiree contributions and
other limitations and the Company has reserved the right to change the
provisions of the plan. The Pioneer Plan is maintained for Pioneer retirees
and dependents only and is subject to deductibles, copayment provisions and
certain maximum payment provisions. The Company does not have the right to
change the Pioneer Plan or to require retiree contributions. Both plans are
self-insured indemnity plans and both coordinate benefits with Medicare as
the primary payer. Neither plan is funded.
The following table reconciles the status of the two plans with the
amount included under other liabilities in the consolidated balance sheet at
December 31, 1995, (in thousands):
MESA Pioneer
Plan Plan Total
------ ------- -------
Accumulated Postretirement Benefit
Obligation ("APBO"):
Retirees and dependents............ $1,080 $11,289 $12,369
Actives - fully eligible........... 353 -- 353
Other actives...................... 731 -- 731
------ ------- -------
Total APBO.................... 2,164 11,289 13,453
Unrecognized Transition Obligation...... (1,420) (2,310) (3,730)
------ ------- -------
Accrued Postretirement
Benefit Obligation.................... $ 744 $ 8,979(a) $ 9,723
====== ======= =======
- ----------
(a) The Company established an accrued liability associated with the
Pioneer Plan in conjunction with its acquisition of Pioneer in
1986.
For measurement purposes, the 1995 annual rate of increase in per
capita cost of covered health care benefits was assumed to be 10% for those
participants under age 65 and 9% for those participants over age 65. The
rates were assumed to decrease gradually to 5.0% by the year 2000 and to
remain at that level thereafter. The health care cost trend rate assumption
affects the amount of the Transition Obligation and periodic cost reported.
An increase in the assumed health care cost trend rates by 1% in each year
would increase the APBO as of December 31, 1995, by approximately $735,000
and the net periodic postretirement benefit cost for the year ended December
31, 1995, by approximately $77,000. The net periodic postretirement benefit
cost for the year ended December 31, 1995, was approximately $1.4 million
based on the assumptions used.
The discount rate used in determining the APBO as of December 31, 1995,
was 8%.
The following table presents the Company's cost of postretirement
benefits other than pensions for the years ended December 31 (in thousands):
1995 1994 1993
------ ------ ------
Net periodic postretirement benefit cost:
Service cost............................ $ 124 $ 110 $ 96
Interest cost........................... 1,005 988 988
Amortization of Transition Obligation... 276 276 276
------ ------ ------
$1,405 $1,374 $1,360
====== ====== ======
Actual costs of providing benefits:
MESA Plan............................... $ 4 $ 120 $ 123
Pioneer Plan............................ 918 666 909
------ ------ ------
$ 922 $ 786 $1,032
====== ====== ======
(11) Major Customers
===============
In 1995 revenues include sales to Mapco Petroleum, Inc. ("Mapco") of
$75.0 million (34.4%) and Western Resources, Inc. ("WRI") of $21.9 million
(10.0%). In 1994 revenues included sales to Mapco of $70.9 million (31.4%),
WRI of $37.4 million (16.6%), and Energas Company of $22.8 million (10.1%).
In 1993 revenues included sales to Mapco of $60.2 million (27.5%), WRI of
$51.8 million (23.6%) and Natural Gas Clearinghouse of $23.1 million
(10.5%).
(12) Concentrations of Credit Risk
=============================
Substantially all of the Company's accounts receivable at December 31,
1995, result from oil and gas sales and joint interest billings to third
party companies in the oil and gas industry. This concentration of
customers and joint interest owners may impact the Company's overall credit
risk, either positively or negatively, in that these entities may be
similarly affected by changes in economic or other conditions. In
determining whether or not to require collateral from a customer or joint
interest owner, the Company analyzes the entity's net worth, cash flows,
earnings, and credit ratings. Receivables are generally not collateralized.
Historical credit losses incurred by the Company on receivables have not
been significant.
(13) Condensed Consolidating Financial Statements
============================================
The Company conducts its operations through various direct and indirect
subsidiaries. On December 31, 1995, the Company's direct subsidiaries were
MOC, Mesa Holding Co. ("MHC") and Hugoton Management Co. ("HMC"). MOC owns
all of the Company's interest in the West Panhandle field of Texas, the Gulf
Coast and the Rocky Mountain areas, as well as an approximate 99% limited
partnership interest in HCLP. MHC owns cash and securities, an approximate
1% limited partnership interest in HCLP and 100% of Mesa Environmental
Ventures Co. ("Mesa Environmental"), a company established to compete in the
natural gas vehicle market. HMC owns the general partner interest of HCLP.
(See discussion below for 1994 changes in subsidiaries and HCLP ownership.)
HCLP owns substantially all of the Company's Hugoton field natural gas
properties and is liable for the HCLP Secured Notes (see Note 4). The
assets and cash flows of HCLP that are subject to the mortgage securing the
HCLP Secured Notes are dedicated to service the HCLP Secured Notes and are
not available to pay creditors of the Company or its subsidiaries other than
HCLP. MOC and the Company are liable for the Credit Agreement, the 13-1/2%
subordinated notes and the Discount Notes. Mesa Capital Corp. ("Mesa
Capital"), a wholly owned financing subsidiary of MOC, is also an obligor
under the 13-1/2% subordinated notes and the Discount Notes. Mesa Capital,
which has insignificant assets and results of operations, is included with
MOC in the condensed consolidating financial statements. Other Company
subsidiaries in the condensed consolidating financial statements include
MHC, HMC, and Mesa Environmental.
In early 1994 the Company effected a series of merger transactions
which resulted in the conversion of the predecessors of MOC, MHC, and the
other subsidiary partnerships, other than HCLP, to corporate form and
eliminated all of the General Partner's minority interests in the
subsidiaries.
As of December 31, 1993, MHC had intercompany payables to MOC of
approximately $123 million. On February 28, 1994, MHC assigned an 18%
limited partnership interest in HCLP (out of its total interest of
approximately 19%) to MOC in satisfaction of $90 million of intercompany
payables. Provisions of the Discount Note indentures required the repayment
of intercompany indebtedness to specified levels and provided that any HCLP
limited partnership interests transferred in satisfaction of intercompany
debt would be valued at $5 million for each one percent of interest
assigned. MHC repaid an additional $33 million of intercompany debt to MOC
in cash during 1994. As a result of these transactions, MOC now owns 99% of
the limited partnership interest in HCLP, and all of MHC's intercompany debt
to MOC which was outstanding at December 31, 1993, was eliminated.
The following are condensed consolidating financial statements of MESA
Inc., HCLP, MOC, and the Company's other subsidiaries combined (in
millions):
Condensed Consolidating Balance Sheets
- --------------------------------------
Other Consol. The
MESA Company and Company
December 31, 1995 Inc. HCLP MOC Subs. Elimin. Consol'd
- ----------------- ------ ------ ------ -------- -------- --------
Assets:
Cash and cash
investments....... $ - $ 47 $ 38 $ 64 $ - $ 149
Other current
assets............ - 20 53 15 - 88
------ ------ ------ ------ ------ ------
Total current
assets.......... - 67 91 79 - 237
------ ------ ------ ------ ------ ------
Property, plant
and equipment,
net............... - 602 478 3 - 1,083
Investment in
subsidiaries...... 76 - 115 10 (201) -
Intercompany
receivables....... - - 9 - (9) -
Other noncurrent
assets............ - 82 58 5 - 145
------ ------ ------ ------ ------ ------
$ 76 $ 751 $ 751 $ 97 $ (210) $1,465
====== ====== ====== ====== ====== ======
Liabilities and
Equity:
Current
liabilities....... $ - $ 64 $ 128 $ 1 $ - $ 193
Long-term debt..... - 471 665 - - 1,136
Intercompany
payables.......... 9 - - - (9) -
Other noncurrent
liabilities....... - - 66 3 - 69
Partners'/Stock-
holders' equity
(deficit)......... 67 216 (108) 93 (201) 67
------ ------ ------ ------ ------ ------
$ 76 $ 751 $ 751 $ 97 $ (210) $1,465
====== ====== ====== ====== ====== ======
Other Consol. The
MESA Company and Company
December 31, 1994 Inc. HCLP MOC Subs. Elimin. Consol'd
- ----------------- ------ ------ ------ -------- -------- --------
Assets:
Cash and cash
investments....... $ - $ 50 $ 24 $ 70 $ - $ 144
Other current
assets............ - 16 39 6 - 61
------ ------ ------ ------ ------ ------
Total current
assets.......... - 66 63 76 - 205
------ ------ ------ ------ ------ ------
Property, plant
and equipment,
net............... - 626 503 1 - 1,130
Investment in
subsidiaries...... 134 - 126 10 (270) -
Intercompany
receivables....... - - 9 - (9) -
Other noncurrent
assets............ - 88 58 3 - 149
------ ------ ------ ------ ------ ------
$ 134 $ 780 $ 759 $ 90 $ (279) $1,484
====== ====== ====== ====== ====== ======
Liabilities and
Equity:
Current
liabilities....... $ - $ 47 $ 41 $ 1 $ - $ 89
Long-term debt..... - 505 688 - - 1,193
Intercompany
payables.......... 9 - - - (9) -
Other noncurrent
liabilities....... - - 73 4 - 77
Partners'/Stock-
holders' equity
(deficit)......... 125 228 (43) 85 (270) 125
------ ------ ------ ------ ------ ------
$ 134 $ 780 $ 759 $ 90 $ (279) $1,484
====== ====== ====== ====== ====== ======
Condensed Consolidating Statements of Operations
- ------------------------------------------------
Years Ended:
- ------------
Other Consol. The
MESA Company and Company
December 31, 1995 Inc. HCLP MOC Subs. Elimin. Consol'd
- ----------------- ------ ------ ------ -------- -------- --------
Revenues............. $ - $ 97 $ 137 $ 1 $ - $ 235
------ ------ ------ ------ ------ ------
Costs and Expenses:
Operating,
exploration and
taxes............. - 28 49 - - 77
General and
administrative.... - - 24 3 - 27
Depreciation,
depletion and
amortization...... - 34 49 - - 83
------ ------ ------ ------ ------ ------
- 62 122 3 - 187
------ ------ ------ ------ ------ ------
Operating Income
(Loss).............. - 35 15 (2) - 48
------ ------ ------ ------ ------ ------
Interest expense, net
of interest income.. - (47) (91) 5 - (133)
Equity in loss of
subsidiaries........ (58) - (11) - 69 -
Other................ - - 21 6 - 27
------ ------ ------ ------ ------ ------
Net Income (Loss).... $ (58) $ (12) $ (66) $ 9 $ 69 $ (58)
====== ====== ====== ====== ====== ======
Other Consol. The
MESA Company and Company
December 31, 1994 Inc. HCLP MOC Subs. Elimin. Consol'd
- ----------------- ------ ------ ------ -------- -------- --------
Revenues............. $ - $ 113 $ 116 $ - $ - $ 229
------ ------ ------ ------ ------ ------
Costs and Expenses:
Operating,
exploration and
taxes............. - 30 49 - - 79
General and
administrative.... - - 26 3 - 29
Depreciation,
depletion and
amortization...... - 37 55 - - 92
------ ------ ------ ------ ------ ------
- 67 130 3 - 200
------ ------ ------ ------ ------ ------
Operating Income
(Loss).............. - 46 (14) (3) - 29
------ ------ ------ ------ ------ ------
Interest expense, net
of interest income.. - (47) (87) 3 - (131)
Losses on
dispositions of
oil and gas
properties.......... - - - (91)(d) 91 -
Equity in loss of
subsidiaries........ (83) - (1) - 84 -
Other................ - - 22 15 (18) 19
------ ------ ------ ------ ------ ------
Net Loss............. $ (83) $ (1) $ (80) $ (76) $ 157 $ (83)
====== ====== ====== ====== ====== ======
Other Consol. The
MESA Company and Company
December 31, 1993 Inc. HCLP MOC Subs. Elimin. Consol'd
- ----------------- ------ ------ ------ -------- -------- --------
Revenues............. $ - $ 103 $ 120 $ (1) $ - $ 222
------ ------ ------ ------ ------ ------
Costs and Expenses:
Operating,
exploration and
taxes............. - 27 48 - - 75
General and
administrative.... - - 23 2 - 25
Depreciation,
depletion and
amortization...... - 35 65 - - 100
------ ------ ------ ------ ------ ------
- 62 136 2 - 200
------ ------ ------ ------ ------ ------
Operating Income
(Loss).............. - 41 (16) (3) - 22
------ ------ ------ ------ ------ ------
Interest expense, net
of interest income.. - (50) (83) 2 - (131)
Intercompany interest
income (expense).... - - 16 (16) - -
Gains of dispositions
of oil and gas
properties.......... - - 10 - - 10
Equity in loss of
subsidiaries........ (102) - (7) (2) 111 -
Other................ - - (42) 29 10 (3)
------ ------ ------ ------ ------ ------
Net Income (Loss).... $ (102) $ (9) $ (122) $ 10 $ 121 $ (102)
====== ====== ====== ====== ====== ======
Condensed Consolidating Statements of Cash Flows
- ------------------------------------------------
Years Ended:
- ------------
Other Consol. The
MESA Company and Company
December 31, 1995 Inc. HCLP MOC Subs. Elimin. Consol'd
- ----------------- ------ ------ ------ -------- -------- --------
Cash Flows from
Operating Activities $ - $ 20 $ 50 $ (1) $ - $ 69
------ ------ ------ ------ ------ ------
Cash Flows from
Investing Activities:
Capital
expenditures...... - (10) (30) (2) - (42)
Other.............. - - 4 (3) - 1
------ ------ ------ ------ ------ ------
- (10) (26) (5) - (41)
------ ------ ------ ------ ------ ------
Cash Flows from
Financing Activities:
Repayments of
long-term debt.... - (16) (10) - - (26)
Other.............. - 4 - - - 4
------ ------ ------ ------ ------ ------
- (12) (10) - - (22)
------ ------ ------ ------ ------ ------
Net Increase (Decrease)
in Cash and Cash
Investments......... $ - $ (2) $ 14 $ (6) $ - $ 6
====== ====== ====== ====== ====== ======
Other Consol. The
MESA Company and Company
December 31, 1994 Inc. HCLP MOC Subs. Elimin. Consol'd
- ----------------- ------ ------ ------ -------- -------- --------
Cash Flows from
Operating Activities $ - $ 41 $ (15) $ 23 $ - $ 49
------ ------ ------ ------ ------ ------
Cash Flows from
Investing Activities:
Capital
expenditures...... - (7) (26) - - (33)
Contributions to
subsidiaries...... (93) - (5) (1) 99 -
Distributions from
subsidiaries...... - - 10 - (10) -
Other.............. - - 28 (2) (33) (7)
------ ------ ------ ------ ------ ------
(93) (7) 7 (3) 56 (40)
------ ------ ------ ------ ------ ------
Cash Flows from
Financing Activities:
Issuance of
common stock...... 93 - - - - 93
Repayments of
long-term debt.... - (21) (154) - - (175)
Long-term
borrowings........ - - 78 - - 78
Contributions from
equity holders.... - 6 93 - (99) -
Distribution to
partners.......... - (10) - - 10 -
Other.............. - 1 (1) (33) 33 -
------ ------ ------ ------ ------ ------
93 (24) 16 (33) (56) (4)
------ ------ ------ ------ ------ ------
Net Increase (Decrease)
in Cash and Cash
Investments......... $ - $ 10 $ 8 $ (13) $ - $ 5
====== ====== ====== ====== ====== ======
Other Consol. The
MESA Company and Company
December 31, 1993 Inc. HCLP MOC Subs. Elimin. Consol'd
- ----------------- ------ ------ ------ -------- -------- --------
Cash Flows from
Operating Activities $ - $ 21 $ 16 $ (4) $ - $ 33
------ ------ ------ ------ ------ ------
Cash Flows from
Investing Activities:
Capital
expenditures...... - (8) (21) (1) - (30)
Proceeds from
dispositions of
oil and gas
properties........ - - 26 - - 26
Other.............. - - 30 46 (35) 41
------ ------ ------ ------ ------ ------
- (8) 35 45 (35) 37
------ ------ ------ ------ ------ ------
Cash Flows from
Financing Activities:
Repayments of
long-term debt.... - (39) (41) - - (80)
Other.............. - 2 (10) (35) 35 (8)
------ ------ ------ ------ ------ ------
- (37) (51) (35) 35 (88)
------ ------ ------ ------ ------ ------
Net Increase (Decrease)
in Cash and Cash
Investments......... $ - $ (24) $ - $ 6 $ - $ (18)
====== ====== ====== ====== ====== ======
Notes to Condensed Consolidating Financial Statements
- -----------------------------------------------------
(a) These condensed consolidating financial statements should be read
in conjunction with the consolidated financial statements of the
Company and notes thereto of which this note is an integral part.
(b) As of December 31, 1995, the Company owns 100% interest in each of
MOC, MHC, and HMC. These condensed consolidating financial
statements present the Company's investment in its subsidiaries
and MOC's and MHC's investments in HCLP using the equity method.
Under this method, investments are recorded at cost and adjusted
for the parent company's ownership share of the subsidiary's
cumulative results of operations. In addition, investments
increase in the amount of contributions to subsidiaries and
decrease in the amount of distributions from subsidiaries.
(c) The consolidation and elimination entries (i) eliminate the equity
method investment in subsidiaries and equity in income (loss) of
subsidiaries, (ii) eliminate the intercompany payables and
receivables, (iii) eliminate other transactions between
subsidiaries including contributions and distributions, and (iv)
establish the General Partner's minority interest in the
consolidated results of operations and financial position of the
Company.
(d) The condensed consolidating statement of operations of MHC for the
year ended December 31, 1994, reflects a $91 million loss from its
disposition of an 18% equity interest in HCLP. The HCLP equity
interest was used to repay a portion of MHC's intercompany payable
to MOC and was valued, in accordance with the provisions of the
Discount Note indentures, at $5 million for each one percent of
interest assigned. A loss was recognized for the difference
between the carrying value of the HCLP interest assigned to MOC
and the $90 million value attributed to such interests which
reduced the intercompany payable. The loss recognized by MHC is
eliminated in consolidation.
F-7
<PAGE>
SUPPLEMENTAL FINANCIAL DATA
===========================
Oil and Gas Reserves and Cost Information
- -----------------------------------------
(Unaudited)
Net proved oil and gas reserves as of December 31, 1995 and 1994, were
estimated by Company engineers. Net proved oil and gas reserves as of
December 31, 1993, associated with the Company's two most significant
natural gas producing fields were estimated by independent petroleum
engineering consultants. These two fields, the Hugoton and West Panhandle
fields, represented over 95% of the Company's net proved equivalent natural
gas reserves as of the date estimated by the independent petroleum
engineers. All of the Company's reserves at December 31, 1995, 1994, and
1993, were in the United States. In accordance with regulations established
by the Commission, the reserve estimates were based on economic and
operating conditions existing at the end of the respective years.
Future prices for natural gas were based on market prices as of each
year end and contract terms, including fixed and determinable price
escalations. Market prices received as of each year end were used for
future sales of oil, condensate and natural gas liquids. Future operating
costs, production and ad valorem taxes and capital costs were based on
current costs as of each year end, with no escalation.
Approximately 65% of the Company's equivalent proved reserves (based on
a factor of six thousand cubic feet ["Mcf"] of gas per barrel of liquids) at
December 31, 1995, is natural gas. The natural gas prices in effect at
December 31, 1995, (having a weighted average of $1.95 per Mcf) were used in
accordance with Commission regulations but may not be the most appropriate
or representative prices to use for estimating reserves since such prices
were influenced by the seasonal demand for natural gas and contractual
arrangements at that date. The average price received by the Company for
sales of natural gas in 1995 was $1.48 per Mcf. Assuming all other
variables used in the calculation of reserve data are held constant, the
Company estimates that each $.10 change in the price per Mcf for natural gas
production would affect the Company's estimated future net cash flows and
present value thereof, both before income taxes, by $109 million and $44
million, respectively. At December 31, 1995, the Company's standardized
measure of future net cash flows from proved reserves (the "Standardized
Measure") and the pretax Standardized Measure were less than the net book
value of oil and gas properties by approximately $100 million and $25
million, respectively. The Company believes that the ultimate value to be
received for production from its oil and gas properties will be greater than
the current net book value of its oil and gas properties.
At December 31, 1993, the Company's internal estimates of proved
reserves for the Hugoton and West Panhandle properties were greater than the
estimates prepared by independent petroleum engineers as of such date. In
the Hugoton field, the primary difference reflects increased reserves for
properties on which the Company drilled 382 infill wells since 1987
resulting from the Company's internal interpretation of pressure and
cumulative production data. In the West Panhandle field, the reserve
differences result from the interpretation of cumulative production data on
producing wells and in the estimates of proved undeveloped reserves.
Oil and gas reserve quantities estimated as of December 31, 1995,
reflect a net increase over 1994, after production, of approximately 171
Bcfe of natural gas. Equivalent natural gas reserves increased in each of
the Company's major production areas. Increases in Hugoton field reserves
reflect alignment of the assumptions used in preparing the proved reserve
estimates with the Company's practice of recovering ethane at the Satanta
Plant. In previous years Hugoton proved reserve estimates were prepared
assuming that the Company would not recover ethane which resulted in
slightly higher natural gas volumes, lower natural gas liquids volumes and
lower total equivalent volumes than if ethane recovery were assumed. The
decision as to whether or not to recover ethane is based on the relative
value of ethane as a liquid versus the energy-equivalent value of such
ethane if left in the residue natural gas. In the future, if economic
conditions warrant, the Company may revise proved reserves to reflect any
changes in such relative values. In the West Panhandle field, reserves were
revised upward to reflect the development drilling results over the past
year and the planned upgrade of the Fain Plant for a higher rate of liquids
recovery per Mcf of gas produced from the field. In the Gulf Coast, reserve
additions resulted from exploratory and development drilling in 1994 and
1995.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting the future rates of production and timing
of development expenditures. Reserve data represent estimates only and
should not be construed as being exact. Estimates prepared by other
engineers might be materially different from those set forth herein.
Moreover, the Standardized Measure should not be construed as the current
market value of the proved oil and gas reserves or the costs that would be
incurred to obtain equivalent reserves. A market value determination would
include many additional factors including (i) anticipated future changes in
oil and gas prices, and production and development costs; (ii) an allowance
for return on investment; (iii) the value of additional reserves, not
considered proved at present, which may be recovered as a result of further
exploration and development activities; and (iv) other business risks.
Capitalized Costs and Costs Incurred
- ------------------------------------
(Unaudited)
Capitalized costs relating to oil and gas producing activities at
December 31, 1995, 1994, and 1993 and the costs incurred during the years
then ended are set forth below (in thousands):
1995 1994 1993
Capitalized Costs: ---------- ---------- ----------
Proved properties................ $1,897,168 $1,865,004 $1,845,483
Unproved properties.............. 2,995 2,838 754
Accumulated depreciation,
depletion and amortization..... (834,304) (753,827) (670,706)
---------- ---------- ----------
Net......................... $1,065,859 $1,114,015 $1,175,531
========== ========== ==========
Costs Incurred:
Exploration and development:
Proved properties........... $ 269 $ 523 $ 73
Unproved properties......... 157 2,425 17
Exploration costs........... 8,167 5,157 2,705
Development costs........... 14,572 14,043 2,381
---------- ---------- ----------
Total exploration and
development.......... 23,165 22,148 5,176
---------- ---------- ----------
Plants and facilities:
Processing plants........... 1,850 3,248 17,501
Field compression facilities 10,561 3,129 4,387
Other....................... 3,354 5,168 2,257
---------- ---------- ----------
Total plants and
facilities........... 15,765 11,545 24,145
---------- ---------- ----------
Total costs incurred............. $ 38,930 $ 33,693 $ 29,321
========== ========== ==========
Depreciation, depletion
and amortization............... $ 80,513 $ 89,413 $ 96,774
========== ========== ==========
<PAGE>
Estimated Quantities of Reserves
- --------------------------------
(Unaudited) Years Ended December 31
------------------------------------
Natural Gas (MMcf) 1995 1994 1993
- ----------- ---------- ---------- ----------
Proved Reserves:
Beginning of year................ 1,303,187 1,202,444 1,276,049
Extensions and discoveries.. 29,728 6,211 5,132
Purchases of producing
properties................ 1,000 822 166
Revisions of previous
estimates................. (38,574) 176,049 7,284
Sales of producing
properties................ -- -- (6,367)
Production.................. (77,312) (82,339) (79,820)
---------- ---------- ----------
End of year...................... 1,218,029 1,303,187 1,202,444
========== ========== ==========
Proved Developed Reserves:
Beginning of year................ 1,257,883 1,159,453 1,223,672
========== ========== ==========
End of year...................... 1,160,751 1,257,883 1,159,453
========== ========== ==========
Years Ended December 31
Natural Gas Liquids, Oil ------------------------------------
and Condensate (MBbls) 1995 1994 1993
- ------------------------ ---------- ---------- ----------
Proved Reserves:
Beginning of year................ 89,428 82,446 87,392
Extensions and discoveries.. 3,121 491 778
Purchases of producing
properties................ 5 1 --
Revisions of previous
estimates................. 26,630 13,947 3,083
Sales of producing
properties................ -- -- (3,019)
Production.................. (7,766) (7,457) (5,788)
---------- ---------- ----------
End of year...................... 111,418 89,428 82,446
========== ========== ==========
Proved Developed Reserves:
Beginning of year................ 85,656 79,294 82,439
========== ========== ==========
End of year...................... 105,197 85,656 79,294
========== ========== ==========
* Proved natural gas liquids, oil and condensate reserve quantities include
oil and condensate reserves at December 31 of the respective years as
follows: 1995, 9,521 MBbls; 1994, 5,031 MBbls; and 1993, 3,296 MBbls.
* In addition to the proved reserves disclosed above, the Company owned
proved helium and carbon dioxide ("CO2") reserves at December 31 of the
respective years as follows: 1995, 3,670 MMcf of helium and 46,459 MMcf
of CO2; 1994, 4,457 MMcf of helium and 46,459 MMcf of CO2; and 1993,
5,198 MMcf of helium and 46,376 MMcf of CO2.
<PAGE>
Standardized Measure of Future Net Cash Flows from Proved Reserves
- ------------------------------------------------------------------
(Unaudited)
December 31
------------------------------------
1995 1994 1993
---------- ---------- ----------
(in thousands)
Future cash inflows................... $3,804,371 $3,513,282 $3,723,760
Future production and
development costs:
Operating costs and
production taxes............... (1,257,957) (1,192,005) (1,337,224)
Development and
abandonment costs.............. (96,594) (95,441) (80,310)
Future income taxes................... (296,987) (211,076) (240,017)
---------- ---------- ----------
Future net cash flows................. 2,152,833 2,014,760 2,066,209
Discount at 10% per annum........ (1,186,644) (1,080,578) (1,079,278)
---------- ---------- ----------
Standardized Measure.................. $ 966,189 $ 934,182 $ 986,931
========== ========== ==========
Future net cash flows
before income taxes................. $2,449,820 $2,225,836 $2,306,226
========== ========== ==========
Standardized Measure
before income taxes................. $1,040,413 $ 988,325 $1,068,740
========== ========== ==========
- ----------
* The estimate of future income taxes is based on the future net cash flows
from proved reserves adjusted for the tax basis of the oil and gas
properties but without consideration of general and administrative and
interest expenses.
<PAGE>
Changes in Standardized Measure
- -------------------------------
(Unaudited)
Years Ended December 31
------------------------------------
1995 1994 1993
---------- ---------- ----------
(in thousands)
Standardized Measure at
beginning of year................... $ 934,182 $ 986,931 $1,037,181
---------- ---------- ----------
Revisions of reserves
proved in prior years:
Changes in prices and
production costs............... 52,724 (121,300) 6,178
Changes in quantity estimates.... 71,673 151,538 17,616
Changes in estimates of
future development and
abandonment costs.............. (18,424) (27,343) 8,054
Net change in income taxes....... (20,081) 27,666 48,703
Accretion of discount............ 98,833 106,874 116,769
Other, primarily timing
of production.................. (94,511) (80,650) (108,371)
---------- ---------- ----------
Total revisions............. 90,214 56,785 88,949
Extensions, discoveries and
other additions, net of future
production and development costs.... 61,259 8,075 4,456
Purchases of proved properties........ 1,692 463 138
Sales of oil and gas produced,
net of production costs............. (154,231) (146,267) (143,502)
Sales of producing properties......... - - (26,907)
Previously estimated development
and abandonment costs incurred
during the period................... 33,073 28,195 26,616
---------- ---------- ----------
Net changes in Standardized Measure... 32,007 (52,749) (50,250)
---------- ---------- ----------
Standardized Measure at end of year... $ 966,189 $ 934,182 $ 986,931
========== ========== ==========
<PAGE>
Quarterly Results
- -----------------
(Unaudited)
Quarters Ended
-------------------------------------------------
March 31 June 30 September 30 December 31
-------- -------- ------------ -----------
(in thousands, except per share data)
1995:
- ----
Revenues............ $ 62,247 $ 59,174 $ 48,967 $ 64,571
======== ======== ======== ========
Gross profit(1)..... $ 44,928 $ 44,066 $ 29,926 $ 45,821
======== ======== ======== ========
Operating income.... $ 15,974 $ 17,080 $ 219 $ 14,692
======== ======== ======== ========
Net loss............ $ (7,894) $(13,953) $(32,473) $ (3,248)(2)
======== ======== ======== ========
Net loss per
common share...... $ (.12) $ (.22) $ (.51) $ (.05)
======== ======== ======== ========
1994:
- ----
Revenues............ $ 61,084 $ 53,361 $ 45,725 $ 68,567
======== ======== ======== ========
Gross profit(1)..... $ 42,214 $ 34,462 $ 28,713 $ 49,387
======== ======== ======== ========
Operating income
(loss)............ $ 10,176 $ 4,867 $ (2,065) $ 15,705
======== ======== ======== ========
Net loss............ $(17,766) $(25,338) $(25,907) $(14,342)
======== ======== ======== ========
Net loss per
common share...... $ (.37) $ (.43) $ (.40) $ (.22)
======== ======== ======== ========
- ----------
(1) Gross profit consists of total revenues less lease operating
expenses and production and other taxes.
(2) In the fourth quarter of 1995 results of operations included net
gains from investments of $18.4 million. (See Note 3 to the
consolidated financial statements of the Company.)
F-8
<PAGE>
<PAGE>
INDEX TO EXHIBITS
-----------------
Exhibit No. Description
----------- -----------
10.14 - Amarillo Supply Agreement between Mesa Operating Limited
Partnership, Seller, and Energas Company, a division of Atmos
Energy Corporation, Buyer, dated effective January 2, 1993.
10.15 - Gas Gathering Agreement-Interruptible between Colorado
Interstate Gas Company, Transporter, and Mesa Operating
Limited Partnership, Shipper, dated effective October 1,
1993, as amended by agreements dated January 1, 1994, January
5, 1994, June 1, 1994, and March 1, 1996.
10.16 - Gas Supply Agreement dated May 11, 1994, between Mesa
Operating Co., as successor to Mesa Operating Limited
Partnership, acting on behalf of itself and as agent for
Hugoton Capital Limited Partnership, and Williams Gas
Marketing Company, and Gas Supply Guarantee dated May 11,
1994.
10.22 - Interruptible Gas Transportation and Sales Agreement dated
January 1, 1991, between Mesa Operating Limited Partnership
and Energas Company and Amendment dated January 1, 1995.
10.23 - "B" Contract Operating Agreement dated January 1, 1988,
between Mesa Operating Limited Partnership and Colorado
Interstate Gas Company.
10.24 - "B" Contract Agreement of Compromise and Settlement dated
May 29, 1987, between Mesa Operating Limited Partnership and
Colorado Interstate Gas Company, and Amendment to Gathering
Agreement dated July 15, 1990.
10.25 - Gas Purchase Agreement dated January 1, 1996, between Mesa
Operating Co., as Seller, and KN Marketing L.P., as Buyer,
and Amendment dated August 1, 1995.
10.26 - Change in Control Retention/Severance Plan adopted August
22, 1995, and Amendment dated October 20, 1995.
22 - List of Subsidiaries of the Company.
27 - Article 5 of Regulation S-X Financial Data Schedule
for Year-End 1995 Form 10-K.
28 - Summary Report of the Company relating to proved oil and gas
reserves at December 31, 1995.
AMARILLO SUPPLY AGREEMENT
This Agreement is made and entered into effective the 2nd day of
January, 1993 by and between MESA Operating Limited Partnership, a Delaware
limited partnership, ("SELLER") and Energas Company a division of Atmos
Energy Corporation, a Texas Corporation ("BUYER").
WITNESSETH:
WHEREAS, SELLER and BUYER are the respective successors to that
certain Agreement between Amarillo Oil Company and Amarillo Gas Company,
dated June 27, 1949, ("Amarillo Supply Contract"); and
WHEREAS, SELLER and BUYER desire to consolidate the Amarillo, Supply
Contract and all amendments thereto into a single document which reflects
the current agreement between SELLER and Buyer;
Now THEREFORE, in consideration of the premises and mutual covenants
and agreements contained herein as well as other valuable consideration,
the sufficiency and receipt of which are hereby acknowledged, SELLER and
BUYER mutually covenant and agree as follows:
I. Amarillo Supply Contract Superseded: Effective January 2, 1993,
-----------------------------------
all provisions of the Amarillo Supply Contract, and all amendments thereto
are terminated and are hereby superseded by the terms of this Agreement.
II. Supply of Gas: (a) SELLER agrees and obligates itself to sell
-------------
and deliver to BUYER, and BUYER agrees to purchase and take from SELLER and
pay for, all volumes of gas made available by SELLER to BUYER and which are
required by BUYER to supply its present and future domestic and commercial
customers located in the City of Amarillo, Texas, and its environs.
(b) In order that BUYER may be assured of an adequate and permanent
supply of gas under the terms and provisions hereof with which to meet its
present and future market requirements, as above defined; BUYER shall have
first call upon residue gas attributable to the gas now owned or controlled
by SELLER under and by virtue of that certain agreement dated January 3,
1928, between the Amarillo Oil Company, predecessor in interest of, the
SELLER and Canadian River Gas Company predecessor, in interest to Colorado
Interstate Gas Company as amended from time to time (the "B" Contract).
BUYER's first call rights to receive "B" Contract residue gas in preference
to SELLER's rights to sell such gas to customers other than Energas shall
be subject to the "B" Contract, as amended by that certain Production
Allocation Agreement dated January 1, 1991, and that certain instrument
entitled Amendment to "B" Contact and Production Allocation Agreement dated
January 1, 1993 (collectively, the PAA) between the SELLER and Colorado
Interstate Gas Company and shall apply only to such volumes of residue gas
as are required to serve BUYER's domestic and commercial customers in the
City of Amarillo and its environs; provided, however, that SELLER shall not
be obligated to deliver to BUYER on a daily basis volumes in excess of the
available residue gas attributable to 100 MMcf per day of SELLER's
production under the "B" Contract.
(c) SELLER will make no sale, transfer, assignment, or other
disposition of its "B" Contract gas rights as are required to serve BUYER's
domestic and commercial customers in the City of Amarillo and its environs,
except subject to the first call rights described herein.
(d) That in the event SELLER shall default in the performance of any
of its obligations hereunder, BUYER shall be subrogated to and entitled to
exercise and enforce all the rights, privileges, remedies of SELLER against
any and all persons and corporations through or from which SELLER's "B"
Contract gas is obtained.
III. Delivery Points and Pressure: The gas purchased hereunder by
----------------------------
BUYER shall be delivered by SELLER to BUYER at the outlet discharge header
of SELLER's Fain Gas Plant and at such other points as may be mutually
agreed upon between BUYER and SELLER.
During periods when the volume of gas demand on BUYER's system is
less than or equal to the maximum volume of gas SELLER is required to
deliver to BUYER's system pursuant to Article II hereof, the deliveries at
the outlet of SELLER's Fain Gas Plant as aforesaid shall be made at
pressures not less than 190# per square inch gauge and not in excess of
400# per square inch gauge, as required from time to time by BUYER.
Notwithstanding the foregoing, if during periods when the volume of gas
demand on BUYER's system is more than the maximum volume of gas SELLER is
required to deliver to BUYER's system pursuant to Article II hereof, then
SELLER's deliveries may be made all pressures less than 190# per square
inch gauge. In the event BUYER desires a minimum delivery pressure in
excess of 190# per square inch gauge then same shall be subject to
negotiations between the parties, provided that BUYER shall give SELLER one
year's advance written notice requesting such future pressure. The
deliveries made at points other than the outlet of SELLER's Fain Gas Plant
shall be made at pressures suitable to BUYER but within the then existing
limitations of SELLER's supply at such points.
IV. Prices and Charges:
------------------
(a) Prices: Except as provided in Section (C) of this Article IV, all
------
gas delivered to BUYER by SELLER pursuant to this Agreement shall be priced
as follows:
A composite price per Mcf for gas delivered hereunder shall be
determined by a formula comprised of a Fixed Price component which will be
utilized for seventy percent (70%) of the composite price, and a Spot Price
component which will be utilized for thirty percent (30%) of the composite
price. Such formula price will be in effect for a period beginning January
2, 1993 and ending December 31, 1997. The pricing of gas to be delivered
hereunder in periods subsequent to December 31, 1997 is described in
Section (c) of this Article IV.
The composite price per Mcf to be paid each month by BUYER sill be
calculated as follows:
Monthly Price = {FP x 0.7) + {(SP + $0.10) (0.3)}
where:
FP = Fixed Price component
SP = Spot Price component
The Fixed Price component shall be determined fore each year by
establishing a fixed Price of $2.71 per Mcf for the initial year of 1993.
The Fixed Price shall be determined for each subsequent year by escalating
the prior year's Fixed Price by five percent (5%) for calendar years 1994
and 1995, and seven and one half percent (7-1/2%) for calendar years 1996
and 1997.
The Fixed Price component of the formula price is thus calculated as
follows:
Year Fixed Price Component Per Mcf
---- -----------------------------
1993 $2.71 = 1993 Fixed Price
1994 $2.71 x 1.05 = 1994 Fixed Price
1995 1994 Fixed Price x 1.05 = 1995 Fixed Price
1996 1995 Fixed Price x 1.075 = 1996 Fixed Price
1997 1996 Fixed Price x 1.075 = 1997 Fixed Price
The Spot Price component shall be determined monthly and shall be
comprised of the hereinafter described Spot Index Price, plus a fee of
$0.10. The parties shall use the first issue of Natural Gas Week published
----------------
each month to determine the Spot Index Price. The Spot Index Price shall
be that price reported in the table titled "Gas Price Report" under the
subheadings "Texas, West, Spot, Delivered to Pipeline" in the "Bid Week"
column for the month of actual delivery. If such index ceases to be
published, or the parties mutually agree that the index ceases to
reasonably reflect the spot price for gas, the parties shall attempt to
agree on a substitute index giving due regard to the purpose and intent in
selecting this original index. If the parties cannot mutually agree on a
substitute index or cannot agree that the index in effect at the time has
ceased to reasonably reflect the spot price for gas delivered hereunder,
then in either of such events, the parties agree that they shall submit the
issue of the alternate selection of an appropriate index to binding
arbitration to be conducted by and under the then existing rules of the
American Arbitration Association ("AAA") within thirty (30) days of written
notification from one party to the other; provided, however, that such
arbitration shall not be conducted more often than once every two years in
the event of disagreement as to whether a particular index reasonably
reflects the spot price for gas. The question of selection of an index
brought about by the cessation of publication of an index being used may be
submitted to arbitration as often as is necessary. The selection of
arbitrators will be conducted pursuant to the process described under
Section (c) of Article IV below and the three arbitrators so chosen will be
required to issue within thirty (30) days from the date of their selection
their decision on the appropriate index to be utilized.
The parties agree that until a new index has been established, the
applicable Spot Price to be used on an interim basis each month will be the
Spot Price for the same month of the prior year plus 5%. As soon as the
new index is established, it will become retroactively effective as of the
first day of the month following the month during which the thirty (30) day
written notification was received by the second party and any required
adjustment will be made within ninety (90) days.
(b) Tax Surcharges: It is understood and agreed that the prices for
gas provided for herein shall be increased or decreased, as the case may
be, to reflect the full amount of any new or additional, or of any increase
or decrease in present rates of severance, gross production, gross
receipts, and excise taxes of any nature whatsoever or similar taxes which,
after January 1, 1993, may be imposed, levied or assessed by any
governmental authority upon the gas sold hereunder, whether or not the same
shall be paid or payable directly or indirectly by SELLER. Taxes being
reimbursed by BUYER to SELLER as of December 31, 1992 will continue to be
reimbursed by BUYER and shall be calculated in the same manner as such
taxes were calculated on December 31, 1992. Applicable laws, rulings or
orders increasing, decreasing or creating any such tax shall be binding and
conclusive upon BUYER until such time as the invalidity thereof has been
finally established by the decision of a court of competent jurisdiction.
In no event, however, shall the provisions of this paragraph be applied or
construed so as to (decrease the prices for gas sold by virtue of this
Agreement below the applicable prices then in effect pursuant to Sections
(a) or (c) of this Article IV. In the event any tax included within this
Section is legally determined to be invalid or unlawfully collected and a
refund thereof is subsequently received by SELLER, then SELLER agrees to
return to BUYER such portion of the refund as may have been applicable to
purchases made by BUYER and paid by BUYER to SELLER, less, SELLER's costs
of recovering such refund.
(c) Future price determinations: The price redetermination procedure
---------------------------
set forth hereinafter shall be employed for each two year period of the
remaining term of the Amarillo Supply Agreement, following the formula
pricing period (1993 - 1997) outlined in (a) above. On or before September
1, 1997, and on or before September I each two nears thereafter, BUYER and
SELLER shall meet to determine the price(s) or pricing formula to be in
effect during each subsequent two year period, commencing January 1, 1998.
If the parties have not redetermined the price(s) or agreed upon a pricing
formula by September 1, 1997, and each September 1 each two years
thereafter, then the parties agree that they shall submit such pricing
determination to binding arbitration to be conducted by, and under the then
existing rules of the AAA within thirty (30) days of written notification
from one party to the other. Within sixty (60) days of such submission,
three arbitrators shall be chosen by the parties from panels supplied by
the AAA. If the parties are unable to select three arbitrators during such
period, the selection of the remaining arbitrator(s) shall be conducted
pursuant to the rules of the AAA governing the selection of arbitrator(s)
when the parties have failed to do so.
The arbitrators so chosen shall be instructed to determine, within
ninety (90) days from their selection, a reasonable price(s) or pricing
formula based on the particular characteristics of the supply under the
Amarillo Supply Agreement at the time of the price redetermination for the
two year period beginning January 1, 1998, or any subsequent two year
period, for which the parties are unable to agree upon a price(s) or
pricing formula. Essential characteristics to be considered by the
arbitrators include the following:
1) The annual volume normally purchased from SELLER by BUYER.
2) The daily volume made, available from SELLER to BUYER during the
various seasons of the year.
3) The average daily volume utilized by BUYER during the course of a
year.
4) The load factor and daily and seasonal swings of BUYER's
Amarillo system demands.
5) The remaining term of the Amarillo Supply Agreement.
The parties agree that until a new price(s) or pricing formula has
been established, the applicable composite price for each month to be used
on an interim basis will be the same as the applicable composite price
established for the same month of the prior year plus 5%. As soon as the
new price(s) or pricing formula is established, it will become
retroactively effective as of the first day of the new pricing period and
any required adjust will be made within ninety (90) days.
V. Quality: All of the gas sold hereunder shall be gasoline plant
-------
residue gas and shall have the following characteristics:
(a) It shall contain not more than twenty five one hundredths (0.25)
grain of hydrogen sulphide per 100 cubic feet measured as herein provided;
(b) The dew point at delivery pressure shall be at least ten degrees
below the existing ground temperature at pipeline depth;
(c) It shall be commercially free of dust, gums, and other solid
matter;
(d) The gas shall have a monthly weighted gross heating value of not
less than nine hundred fifty (950) British Thermal Units per cubic foot.
VI. Meters and Measurement: (a). The volume of gas, delivered
----------------------
hereunder shall be measured by orifice meters installed and maintained as
prescribed in the Gas Measurement Committee Report No. 3, (ANSI/API-2530,
Second Edition) of the American Gas Association and as revised from time to
time. (AGA Report No. 3)
(b) BUYER shall maintain and operate at or near the various points of
delivery, shiftable meters and auxiliary equipment to properly measure the
volumes of gas being delivered. All such measuring equipment shall remain
the sole property of BUYER but the SELLER shall have access to said
metering equipment at all reasonable times. The reading, calibration, and
adjusting of said meters shall be done by the employees or agents of BUYER
and charts and records from such metering equipment shall remain the
property of BUYER, but upon request of SELLER, BUYER will submit to SELLER
the records and charts from said metering equipment together with
calculations therefrom for SELLER's inspection and verification subject to
return by SELLER within a reasonable period of time.
(c) SELLER may, at it option and at its sole cost and expense,
install and operate check metering equipment, but the metering equipment of
BUYER shall be used for determining the amounts of gas delivered under this
Agreement.
(d) The unit of measurement for all gas deliverable under this
Agreement shall be one thousand (1,000) cubic feet of base temperature of
sixty (60) degree Fahrenheit and at a base pressure of 14.65 pounds
absolute and the readings and registrations of all metering equipment shall
be computed into such units in accordance with AGA Report No. 3 referenced
above.
(e) For the purpose of measurement the average atmospheric pressure
shall be assumed to be thirteen (13.0) pounds irrespective of the actual
elevation of the delivery point above sea level or of variations in the
barometric pressure from time to time.
(f) For meters of the orifice type, corrections shall be made for the
following factors:
1) Flowing temperature variation from 60 degrees Fahrenheit;
2) Deviation of the gas from Boyle's Law;
3) Calculations shall be based on specific gravities determined by
chromatograph analysis of the flowing gas stream for the current month,
based upon either a continuous composite sample at the tailgate of the Fain
Plant or a proportional to flow composite sample at the tailgate of the
Fain Plant.
(g) All determinations of physical characteristics, and meter tests
shall be made with standard apparatus and using generally accepted industry
methods at such times and places as in accordance with good practice may be
agreed upon from time to time between SELLER and BUYER.
VII. Billing and Payment: SELLER shall render to BUYER, on or before
-------------------
the tenth (10th) day of each month a statement showing the volume of gas
delivered to BUYER during the calendar month immediately preceding and the
amount of payment or payments then due from BUYER to SELLER for such gas
delivered. In the event an error is discovered in the amount billed in any
statement rendered by SELLER, such error shall be adjusted within thirty
(30) days after a claim is made therefore, but in any event within
twenty-four (24) months from the date of such statement. Failure to make a
written request for a required adjustment within the twenty-four (24) month
period shall be deemed a waiver of that adjustment by the party having such
adjustment rights. Both SELLER and BUYER shall have the right to examine,
at reasonable times, books, records and charts of the other to the extent
necessary to verify the accuracy of any statement, charge or computation
made under to pursuant to any of the provisions hereof.
BUYER agrees to pay SELLER at its office in Amarillo, Texas, or at
such other address designated in writing by SELLER, on or before the 20th
day of each month for all gas delivered hereunder during month according to
the gas measurements and computations and at the prices hereinbefore
provided for and billed on said monthly statement. Should BUYER fail to
pay any amount due SELLER when such amount is due and such failure to pay
continues for sixty (60) days, then SELLER may suspend deliveries of gas,
but the exercise of such right shall be in addition to any and all other
remedies available to SELLER.
VIII. Force Majeure: In the event of either party being rendered
-------------
unable wholly or in part by force majeure to carry out its obligations
-------------
under this Agreement other than to make payments of amounts due hereunder,
it is agreed that on such party giving notice and full particulars of such
force majeure in writing or by telegraph to the other party as soon as
- -------------
possible after the occurrence of the cause relied on, then the obligations
of the party giving such notice so far as they are affected by such force
-----
majeure, shall be suspended during the continuance of any inability so
- -------
caused but for no longer period, and such cause shall, so far as possible,
be remedied with all reasonable dispatch.
The term "force majeure" as employed herein shall mean acts of God,
-------------
strikes, lockouts or other industrial disturbances, acts of the public
enemy, wars, blockades, insurrections, riots, epidemics, landslides,
lightning, earthquakes, fires, storms, floods, washouts, arrests and
restraint of rules and people, civil disturbances, explosions, brakeage or
accident to machinery or lines of pipe, the necessity for making repairs
and/or alterations in machinery or lines of pipe, freezing of wells or
lines of pipe, sudden partial or entire failure of natural gas wells, and
any other cause, whether of the kind herein enumerated, or otherwise, not
within the control of the party claiming suspension and which by the
exercise of due diligence such party is unable to overcome.
IX. Responsibility for Handling: As between the parties hereto,
---------------------------
SELLER shall be in control and possession of the gas deliverable hereunder
and responsible for any damage or injury caused thereby until the same
shall have been delivered to BUYER, after which delivery BUYER shall be
deemed to be in exclusive control and possession thereof and responsible
for any such injury or damage.
X. Termination for Default: If either party shall fail to perform
-----------------------
the covenants or obligations imposed upon it under and by virtue of this
Agreement, then and in such event the other party may, at its option,
terminate this Agreement by proceeding as follows:
The party not in default shall cause written notice to be served on
the party in default, stating specifically the cause for terminating this
Agreement and declaring it to be the intention of the party giving the
notice to terminate the same; thereupon the party in defauft shall have
thirty (30) days after the service of the aforesaid notice in which to
remedy or remove the cause or causes for terminating this Agreement and if,
within said period of thirty (3) days, the party in default does so remove
and remedy said cause or causes and fully indemnifies the party not in
default for any and all consequences of such breach, then such notice shall
be withdrawn and this Agreement shall continue in full force and effect.
In case the party in defauft does not so remedy and remove the cause or
causes and/or does not indemnify the party giving the notice for any and
all consequences of such breach within said period of thirty (30) days, and
if the party giving the notice does not withdraw the notice, then this
Agreement shall become null and void from and after the expiration of said
period. Any cancellation of this Agreement pursuant to the provisions of
this article shall be without prejudice to any right of the party not in
default to collect any amounts then due to and without waiver of any other
remedy to which the party not in default may be entitled for violation of
this Agreement.
XI. Successors and Assigns: This Agreement shall inure to the
----------------------
benefit of and be binding upon the successors and assigns of the
parties hereto, and is intended solely for the benefit of BUYER and SELLER
and their respective successors and assigns and not for the benefit of any
third parties. Whenever the name of any corporation or partnership is used
herein it shall include the successors and assigns of such corporation or
partnership, but neither party hereto may assign this Agreement without the
written consent of the other being first had and obtained, which written
consent shall not be unreasonably withheld.
XII. Term: This Agreement shall be in force and effect from and
----
after January 2, 1993, and shall continue in force and effect for so long
as SELLER has merchantable quantities of gas available hereunder for sale
to BUYER.
XIII. Miscellaneous: (a) This Agreement shall be governed by and
-------------
construed in accordance with the laws of the State of Texas, excluding any
conflicts of law, rule, or other principle which might refer such
construction to the laws of another state. All terms and conditions of
this Agreement were prepared jointly by the SELLER and BUYER and not by any
party to the exclusion of the other.
(b) This Agreement may not be modified or amended except by the
written agreement of the parties hereto.
(c) No waiver by either party hereto of any defauft of the other
party or breach of any provision of the other party under this Agreement
shall operate as, or be deemed to be, a waiver of any other or subsequent
default or breach, whether of a like or different nature.
(d) Each provision and term of this Agreement is intended to be
several. If any term or provision hereof is held to be illegal or invalid
by a court of competent jurisdiction, such illegality or invalidity shall
not affect in any way the validity or legality of the remaining terms or
provisions.
IN WITNESS WHEREOF, the parties hereto have executed this Amarillo
Supply Agreement effective as of the date first above Written.
MESA OPERATING LIMITED PARTNERSHIP
By Pickens Operating Co.,
General Partner
By /s/ S. Leonard Hruzek, Jr.
--------------------------------------
S. Leonard Hruzek, Jr., Vice President
Date September 2, 1993
-----------------
ENERGAS COMPANY, a division of
Atmos Energy Corporation
By /s/ Toby A. Priolo
--------------------------------------
Toby A. Priolo, Vice President
Date August 27, 1993
---------------
Contract No. 42026
GAS GATHERING AGREEMENT - INTERRUPTIBLE
between
COLORADO INTERSTATE GAS COMPANY
and
MESA OPERATING LIMITED PARTNERSHIP
DATED: October 1, 1993
---------------
<PAGE>
GAS GATHERING AGREEMENT - INTERRUPTIBLE
DATE: October 1, 1993
---------------
The Parties identified below, in consideration of their mutual promises
agree as follows:
1. Transporter: Colorado Interstate Gas Company
Shipper: MESA Operating Limited Partnership
2. Term of Agreement: Beginning: October 1, 1993
---------------
Ending: September 30, 1994
------------------
X Month to month with 30-day written notification of termination by
--- by either party.
3. This Agreement supersedes and cancels: Gas Gathering Agreement, as
amended, dated April 1, 1989 (Contract No. 10767).
4. This Agreement is subject to the rates contained in Appendix
"A" and to all of the terms of the attached General Terms and
Conditions - Interruptible Gathering (see Exhibit "A"), except as
adjusted as follows:
No adjustments.
5. Invoices: Shipper: MESA Operating Limited Partnership
5202 North O'Connor Blvd., Suite 1400
Irving, Texas 75039-3746
Attention: Steve Tennison
6. Payments for Gathering: Colorado Interstate Gas Company
Department 208
Denver, Colorado 80291
7. Notices: Transporter: Colorado Interstate Gas Company
P. O. Box 1087
Colorado Springs, Colorado 80944
Attention: Transportation & Exchange
Transportation & Exchange Fax:
(719) 520-4810
Gas Control Fax: (719) 520-4411
Shipper: MESA Operating Limited Partnership
5202 North O'Connor Blvd., Suite 1400
Irving, Texas 75039-3746
Attention: Steve Tennison
Fax: (214) 444-4394
8. Service under this Agreement shall consist of the acceptance by
Transporter of gas Tendered by Shipper to Transporter at the
Point(s) of Receipt listed on Exhibit "B", the gathering of that
gas on an interruptible basis for Delivery (either directly or by
displacement), and the Tender for Delivery of gas to Shipper at the
Point(s) of Delivery.
9. Other Operating Provisions: None.
IN WITNESS WHEREOF, the Parties hereto have executed this Agreement as
of the Day written above.
COLORADO INTERSTATE GAS COMPANY MESA OPERATING LIMITED
(Transporter) PARTNERSHIP
(Shipper)
By: Pickens Operating Co.
General Partner
By: /s/ S. W. Zuckweiler By: /s/ S. L. Hruzek, Jr.
-------------------------- ----------------------
S. W. Zuckweiler S. L. Hruzek, Jr.
Vice President ----------------------
(Print or type name)
Vice President-Marketing and
Land
----------------------
(Print or type title)
752359141
----------------------
(Taxpayer ID Number)
<PAGE>
APPENDIX A
to
GAS GATHERING AGREEMENT - INTERRUPTIBLE
TRANSPORTER: COLORADO INTERSTATE GAS COMPANY
SHIPPER: MESA OPERATING LIMITED PARTNERSHIP
DATE: October 1, 1993
---------------
GATHERING RATES
Commodity
Point(s) of Rate
Gathering Area Delivery (Note 1) Fuel Term of Rate
- -------------- ----------- --------- ---- ------------
Hugoton Lakin Master $0.154 3.0% 10/1/93-10/31/93
Meter per Dth
Hugoton H&P Sunflower $0.185 3.0% 10/1/93-10/31/93
per Dth
Hugoton K N Exchange $0.185 3.0% 10/1/93-10/31/93
per Dth
Note: (1) The Commodity Rate for Service hereunder shall be as agreed
between the Parties, except that in the event that an
effective rate for service in a gathering area is not agreed
to prior to the tender of gas by Shipper for service in that
gathering area, then the rate for that service, until
otherwise agreed, shall be the maximum rate that Transporter
charges for gathering service in that area.
<PAGE>
EXHIBIT "A"
to
GAS GATHERING AGREEMENT - INTERRUPTIBLE
between
COLORADO INTERSTATE GAS COMPANY (Transporter)
and
MESA OPERATING LIMITED PARTNERSHIP (Shipper)
DATED: October 1, 1993
---------------
GENERAL TERMS AND CONDITIONS - INTERRUPTIBLE GATHERING
INDEX
ARTICLE PAGE NO.
- ------- --------
1 DEFINITIONS AND ABBREVIATIONS. . . . . . . . . . . . . .1
2 RATES OF FLOW; OPERATING TOLERANCES; BALANCING . . . . .3
3 APPLICABLE RATE, INCORPORATION BY REFERENCE. . . . . . 13
4 PRIORITY OF SERVICE AND ALLOCATION OF CAPACITY . . . . 14
5 TERMINATION. . . . . . . . . . . . . . . . . . . . . . 15
6 OTHER OPERATING PROVISIONS . . . . . . . . . . . . . . 15
7 PRESSURE . . . . . . . . . . . . . . . . . . . . . . . 17
8 QUALITY SPECIFICATIONS . . . . . . . . . . . . . . . . 18
9 MEASUREMENT. . . . . . . . . . . . . . . . . . . . . . 21
10 BILLING AND PAYMENT. . . . . . . . . . . . . . . . . . 26
11 FORCE MAJEURE. . . . . . . . . . . . . . . . . . . . . 28
12 INTERRUPTIONS OF SERVICE . . . . . . . . . . . . . . . 29
13 TAXES. . . . . . . . . . . . . . . . . . . . . . . . . 30
14 LIABILITY. . . . . . . . . . . . . . . . . . . . . . . 30
15 WARRANTY . . . . . . . . . . . . . . . . . . . . . . . 30
16 RESPONSIBILITY FOR GAS AND PRODUCTS. . . . . . . . . . 31
17 WAIVER . . . . . . . . . . . . . . . . . . . . . . . . 32
18 LIMITATION OF SERVICE. . . . . . . . . . . . . . . . . 32
19 AMENDMENT. . . . . . . . . . . . . . . . . . . . . . . 32
20 MISCELLANEOUS. . . . . . . . . . . . . . . . . . . . . 32
21 ASSIGNMENT . . . . . . . . . . . . . . . . . . . . . . 33
<PAGE>
GENERAL TERMS AND CONDITIONS - INTERRUPTIBLE GATHERING
ARTICLE 1 - DEFINITIONS AND ABBREVIATIONS
- -----------------------------------------
1.1 "Btu" shall mean 1 British thermal unit, which is the amount of
heat required to raise the temperature of 1 pound of water 1 degree from 59
to 60 degrees Fahrenheit.
1.2 "Day" shall mean a period of 24 consecutive hours, beginning at
1:00 p.m. Central Standard Time. Unless otherwise stated, all times in
the Agreement are Central Standard Time.
1.3 "Dth" (Dekatherm) shall mean the quantity of heat energy which is
equivalent to 1,000,000 British Thermal Units. One "dekatherm" of gas
shall mean the quantity of gas which contains one dekatherm of heat energy.
1.4 "Deliver" or "Delivered" shall mean the Tender of a quantity of
natural gas by Transporter to Shipper or to a third party for Shipper's
account under an Agreement.
1.5 "Delivery Quantity" shall mean the quantity, expressed in Dth, of
gas Delivered by Transporter at the Point(s) of Delivery for the account of
Shipper.
1.6 "FERC" or "Commission" shall mean the Federal Energy Regulatory
Commission and any other governmental body or bodies succeeding to,
lawfully exercising, or superseding any powers of the Federal Energy
Regulatory Commission.
1.7 "Gross Heating Value" shall mean the number of Btus produced by
the complete combustion, at a constant pressure, of the amount of gas which
would occupy a volume of 1 cubic foot at a temperature of 60 degrees
Fahrenheit on a water-free basis and at a pressure of 14.73 p.s.i.a. with
air of the same temperature and pressure as the gas, when the products of
combustion are cooled to the initial temperature of the gas and air, and
when the water formed by combustion has condensed to the liquid state.
1.8 "Mcf" shall mean 1,000 cubic feet of gas at a pressure of 14.73
p.s.i.a. and at a temperature of 60 degrees Fahrenheit.
1.9 "Month" shall mean the period of time beginning at 1:00 p.m.
Central Standard Time on the 1st Day of a calendar Month and ending at 1:00
p.m. Central Standard Time on the 1st Day of the succeeding calendar Month.
1.10 "p.s.i.a." shall mean pounds per square inch absolute.
1.11 "p.s.i.g." shall mean pounds per square inch gauge.
1.12 "Party" or "Parties" shall mean either Shipper or Transporter.
1.13 "Point of Delivery" shall be that location where Transporter
Delivers gas for the account of Shipper after gathering.
1.14 "Point of Receipt" shall mean that point where Transporter
receives gas for the account of Shipper for gathering.
1.15 "Products" shall mean liquid and liquefiable hydrocarbons,
inerts (including, but not limited to, helium and nitrogen), sulfur, water,
and any other component of gas removed by processing or compression, or by
means of drips or separators.
1.16 "Receipt Quantity, shall mean the quantity of gas received by
Transporter at the Point(s) of Receipt for the account of Shipper.
1.17 "Shipper" shall mean that party on whose behalf gas is being
gathered.
1.18 "Tender" shall mean making natural gas available in accordance
with all of the provisions of this Gas Gathering Agreement.
1.19 "Thermal Content" when applied to any volume of gas shall mean
the aggregate number of Btus contained in such volume. The Thermal Content
shall be determined by multiplying the volume of gas in cubic feet by the
Gross Heating Value of the gas.
1.20 "Transporter" shall mean Colorado Interstate Gas Company.
ARTICLE 2 - RATES OF FLOW: OPERATING TOLERANCES: BALANCING
- ----------------------------------------------------------
2.1 Rates of Flow. At each Point of Receipt and Point of Delivery,
-------------
each Party shall use its best efforts to deliver, or cause to be delivered,
gas at reasonably uniform hourly and daily rates of flow.
2.2 Balancing Obligations. The following daily balancing obligations
---------------------
shall apply:
(a) Responsibilities of Shipper and Transporter. Transporter
shall, to the extent practicable, Deliver quantities for Shipper's account
concurrently with the receipt of like quantities less the fuel
reimbursement listed in Appendix "A." At no time shall Transporter be
required to receive quantities for Shipper's account in excess of the
quantities Shipper or Shipper's designee will accept at the Point(s) of
Delivery on a concurrent basis plus the applicable fuel reimbursement. It
is recognized that on any Day the quantities received by Transporter at the
Point(s) of Receipt less fuel reimbursement may not equal the quantities
accepted by Shipper or Shipper's designee at the Point(s) of Delivery.
Such variations shall be kept to the minimum and shall be balanced as soon
as practicable. Minimization of daily imbalances shall be Shipper's
responsibility. However, Shipper and Transporter shall manage the receipts
and deliveries so that any Imbalance shall be kept as near zero as
practicable.
(b) Notification. Either Party shall provide written,
telephonic, or electronic notification to the other Party as soon as it is
aware that receipts and deliveries are not in balance.
(c) Corrective Action by Transporter. Transporter reserves the
right, where necessary to reasonably restore balance, to adjust or suspend
receipts or deliveries in order to reduce any out-of-balance conditions.
Transporter shall give at least 27 hours' notice prior to adjustment or
suspension of service under this provision.
(d) Imbalances with Other Parties. Transporter shall not be
responsible for eliminating any imbalances between Shipper and any third
party. Furthermore, Transporter shall not be obligated to deviate from its
standard operating and accounting procedures in order to reduce or
eliminate any such imbalances.
2.3 Definitions, Classification, and Initial Treatment of Imbalances.
----------------------------------------------------------------
(a) Definitions.
(i) "Imbalance." For purposes of this Article,
"Imbalance" shall mean the cumulative difference between the Dth received
hereunder by Shipper or Shipper's designee at the Point(s) of Delivery, and
the Dth received hereunder by Transporter for Shipper's account at the
Point(s) of Receipt upstream of the corresponding Point(s) of Delivery as
those Receipt Quantities are adjusted for Fuel Reimbursement, during the
term of the Agreement up to the date that the determination of said
cumulative difference is made. The cumulative difference shall be
determined for each set of corresponding Point(s) of Receipt and Delivery
(in each gathering system) under the Agreement.
(ii) "Imbalance Percentage." For purposes of this Article,
"Imbalance Percentage" for each gathering system under this Agreement shall
mean a fraction, expressed in terms of percentage, the numerator of which
is the Imbalance in Dth in a gathering system in a Month and the
denominator of which is total Dth received in that gathering system in the
Month for which the Imbalance is calculated. The Imbalance Percentage
shall be calculated separately for each set of corresponding Point(s) of
Receipt and Delivery (in each gathering system) under the Agreement.
(b) Resolution of Imbalances. Shipper shall eliminate an
Imbalance by any method set forth in Section 2.4 within 60 Days following
notification by Transporter of the Imbalance. Any Imbalance not resolved
within the 60-Day balancing period shall be eliminated by use of the Cash
Out provision set forth in Section 2.4(e) below.
(c) Balancing Upon Termination. Upon termination of the
Agreement, any remaining Imbalance will be eliminated by use of one or more
of the methods set forth in Section 2.4 at the earliest practicable date.
Provided, however, that any Imbalance not eliminated within 60 days of
termination of the Agreement will be eliminated by the Cash Out provision
set forth in Section 2.4(e) below, without application of the Index Price
Adjustment Factor.
(d) Prioritization of Payback Volumes. Transporter shall
schedule all gas being returned to Transporter to correct: Imbalances after
all gas Tendered under firm and interruptible agreements has been
scheduled. However, should Imbalance quantities scheduled for payback not
be delivered to Transporter without a minimum of 48 hours' notice, such
quantities shall be subject to the provisions of Section 2.4(e) as of the
end of the Month in which the gas as scheduled. Transporter shall schedule
all gas being returned to Shipper to correct Imbalances consistent with the
Agreement governing the payback of gas.
2.4 Imbalance Reduction or Elimination.
----------------------------------
(a) Payback Nominations. Shipper may nominate payback
quantities to Transporter to reduce imbalances. Transporter's acceptance
of such nominations shall be subject to any operational constraints on
Transporter's gathering, transportation, and storage facilities at the time
of such nominations.
(b) Imbalance Transfer, The term "Imbalance Transfer" shall
refer to the process by which an individual Shipper's total Imbalances are
reduced or eliminated by offsetting Imbalances under one or more of
Shipper's Agreements by Imbalances under one or more of Shipper's other
Agreements. To be eligible for an Imbalance Transfer. the Imbalances must
be at corresponding Point(s) of Receipt and Delivery in the same gathering
system, subject to the same gathering rate and under the same class of
service. Upon request of Shipper. Transporter shall permit an Imbalance
Transfer without any unduly discriminatory restrictions on Shipper's
receipt point flexibility. Provided, however, only those Imbalance
Transfers that reduce individual Agreement Imbalances will be permitted
(i.e., the maximum quantity which may be transferred is the smaller of the
excess or shortfall under the Agreements affected by the transfer).
(c) Imbalance Swap. The term "Imbalance Swap" shall refer to
the process by which the total Imbalances of two Shippers are reduced or
eliminated by offsetting Imbalances under one or more of one Shipper's
Agreements by Imbalances under one or more of another Shipper's Agreements.
To be eligible for an Imbalance Swap, the Imbalances must be at
corresponding Point(s) of Receipt and Delivery in the same gathering
system, subject to the same gathering rate and under the same class of
service.
(i) Transporter will permit Imbalance Swaps, without any
unduly discriminatory restrictions on Shipper's receipt point flexibility;
provided, however, only those Imbalance Swaps that reduce individual
Agreement Imbalances will be permitted (i.e., the maximum quantity which
may be swapped is the smaller of the excess or shortfall under the
*Agreements affected by the swap).
(ii) A shipper, acting without the assistance of
Transporter, may negotiate an Imbalance Swap arrangement with another
Shipper.
(iii) A Shipper may request, in writing, for Transporter to
post on Transporter's electronic bulletin board, the Shipper's willingness
and availability for an Imbalance Swap. Such posting shall include the
Agreements to be included and the quantity to be encompassed by the
Imbalance Swap (by gathering area), the Shipper's contact names and phone
numbers and any special conditions.
(iv) Shippers shall negotiate the terms of Imbalance Swaps
among themselves.
(v) Shippers intending to implement an Imbalance Swap must
so notify Transporter and Tender to Transporter a fully executed Imbalance
Swap Agreement in the form of the agreement included herein at the end of
this Article.
(d) Applicable Charges. Transporter shall not charge for
Imbalance Swaps or for Imbalance Transfers.
(e) Cash Out. The term "Cash Out" shall refer to the reduction
or elimination of an Imbalance by a payment made by Shipper to Transporter
(if the cumulative Thermal Content of the quantities received by Shipper or
Shipper's designee under the Agreement exceeds the cumulative Thermal
Content of the Receipt Quantities less fuel reimbursement) or by
Transporter to Shipper (if the cumulative Thermal Content of the Receipt
Quantities less fuel reimbursement exceeds the cumulative Thermal Content
of the quantities received by Shipper or Shipper's designee). This payment
shall be calculated pursuant to this Section 2.4(e). Payment of a Cash Out
charge will result in reduction of Shipper's Imbalance by the Imbalance
Cashed Out. In the event of a Cash Out payment by Shipper to Transporter,
Shipper shall also pay the gathering charges applicable in the month of the
Cash Out on the quantity of gas Cashed Out.
(i) "Index Price" shall mean the applicable price published
in Inside FERC's Gas Market Report as the final monthly index price for the
-------------------------------
Month in which the Imbalance is being resolved. The Index Prices for the
Northern and Southern/Central Gathering Systems shall be:
South of Denver - Simple average of prices published for ANR-Oklahoma,
NGPL-Oklahoma, NNG-Oklahoma, and PEPL-Oklahoma.
North of Denver - CIG-Rocky Mountains
If the Gas Market Report is unavailable, Transporter shall base the
Index Prices on index prices posted in a similar publication. The
applicable Index Prices shall be stated in Dth's. Transporter shall post
the Index Prices on Transporter's electronic bulletin board during the
Month the Index Prices are effective.
(ii) Determination of Cash Out Payment. For purposes of
Cash Out, Shipper's Imbalance Percentage shall be distributed among Cash
Out Layers as reflected below. The portion of the Shipper's Imbalance
Percentage that is distributed to a particular Cash Out Layer is the
"Distributed Imbalance Percentage". The total Cash Out payment due to
Transporter from Shipper or to Shipper from Transporter shall be the sum of
the amounts calculated for each Cash Out Layer for the Imbalance to be
reduced or eliminated. The amount attributable to each Cash Out Layer
shall be calculated by multiplying the MMBtu that underlie the Distributed
Imbalance Percentage to be reduced or eliminated times the appropriate
Index Price under Section 2.4(e)(I) times the applicable Index Price
Adjustment Factor determined as follows:
Index Price Adjustment Factor
-----------------------------
Cash Out Distributed (If Gas Is Due (If Gas Is Due
Layer Imbalance Percentage Transporter) Shipper)
- -------- -------------------- -------------- --------------
1 0 - 5% 1.0 1.0
2 >5% - 10% 1.10 0.90
3 >10% - 15% 1.15 0.85
4 >15% - 20% 1.20 0.80
5 >20% 1.25 0.75
(iii) Imbalances related to higher Cash Out Layers shall be
Cashed Out before those related to lover Cash Out Layers (i.e., Imbalances
in Layer 5 will be Cashed Out before Imbalances in Layer 4, those in Layer
4 will be Cashed Out before those in Layer 3, etc.).
(iv) Cash Out payments due Shipper or Transporter shall be
subject to the provisions of Article 10 of these General Terms and
Conditions.
<PAGE>
IMBALANCE SWAP AGREEMENT
between
COLORADO INTERSTATE GAS COMPANY
and
---------------------
and
---------------------
DATED:
-------------
<PAGE>
IMBALANCE SWAP AGREEMENT
This Agreement is made and entered into this ___ day of ________,19__,
by and between Colorado Interstate Gas Company ("Transporter"), Shipper A
("A"), and Shipper B ("B").
WITNESSETH
WHEREAS A has one or more Gathering Agreements with Transporter; and
WHEREAS B has one or more Gathering Agreements with Transporter; and
WHEREAS A and B have opposing gathering imbalances due to or by
Transporter under such Gathering Agreements; and
WHEREAS A and B desire to resolve all or a part of their respective
gathering imbalances with Transporter.
NOW, THEREFORE. A, B, and Transporter agree as follows:
1. A and B desire to reduce their respective imbalances by
_______MMBtu, including imbalances related to each Point of Delivery under
Paragraph 2 below. As of ___________ , 19__, the net imbalance under A's
Gathering Agreement(s) due to Transporter and under B's Gathering
Agreement(s) due from Transporter is equal to or in excess of the
quantities for the Point(s) of Delivery listed in Paragraph 2 below.
2. To such end, A and B mutually agree to exchange _______MMBtu of
their respective imbalances, the content of which is:
Shipper A Shipper B
- -------------------------------- -------------------------------
Gathering Gathering
System System
Point(s) Point(s
Agreement Of Delivery MMBtu Agreement Of Delivery MMBtu
- --------- ----------- ----- --------- ----------- -----
3. Transporter agrees to effect the exchange proposed by A and B such
that an off-setting reduction of the imbalances due to Transporter by A (at
the Point(s) of Receipt upstream of the Point(s) of Delivery listed above)
and due to B by Transporter (at the corresponding Point(s) of Delivery
listed above) under their respective Agreements will result.
4. Transporter, A and B agree that the exchange of ______MMBtu as set
forth herein is final. Any change of fact, including required retroactive
adjustments, which may affect the beginning imbalances referenced in this
Agreement will only affect the Agreement under which the imbalance occurred
and will not affect the exchange resulting from execution of this
Agreement.
5. Transporter shall not revise the original billing for the
quantities affected by this Imbalance Swap Agreement. The Shipper billed
for gathering of the quantities swapped hereunder shall remain responsible
for payment of such charges.
IN WITNESS WHEREOF, the Parties hereto have executed this Agreement.
SHIPPER A
By _______________________
SHIPPER B
By _______________________
COLORADO INTERSTATE GAS C0MPANY
By _______________________
<PAGE>
ARTICLE 3 - APPLICABLE RATE, INCORPORATION BY REFERENCE
- -------------------------------------------------------
3.1 Rate. The rates for service hereunder shall be as listed on
----
Appendix "A", which is attached to the Gas Gathering Agreement and made a
part thereof. The rates hereunder shall not exceed the maximum rates nor
be less than the minimum rates for gathering set forth in Transporter's
FERC Gas Tariff.
3.2 Charges. Shipper shall each Month be charged an amount obtained
-------
by multiplying the Commodity Rate by the Receipt Quantity for that Month
for each gathering system.
3.3 Changes in Rates and Terms. If the FERC directly or
--------------------------
indirectly requires changes in the costs attributable to the gathering
service hereunder, then, effective as of the date of such change, the
gathering rate(s) applicable to the service provided hereunder shall be
changed to reflect the full recovery of costs attributed to such service,
including retroactive recovery of costs where the gathering rate(s)
applies. If the FERC directly or indirectly imposes any area or system
wide maximum rate for gathering, or otherwise requires an adjustment to the
gathering rate(s) and such action(s) places Transporter in a position which
is not economically or contractually equivalent to the position originally
agreed upon, Transporter shall so notify Shipper. Upon receipt of such
notice, the Parties shall commence discussions within 10 Days and
thereafter diligently pursue, in good faith, the negotiation and execution
of an amendment to this Agreement which results in the Parties being placed
in the same economic and contractual position originally agreed upon. If
the Parties are unable to reach agreement in such negotiations within a
reasonable time (as determined by either Party in good faith), either Party
may terminate this Agreement upon 10 Days' prior written notice.
ARTICLE 4 - PRIORITY OF SERVICE AND ALLOCATION OF CAPACITY
- ----------------------------------------------------------
4.1 Priority of Service Status and Allocation of Capacity Procedures.
----------------------------------------------------------------
Shippers for whom Transporter has agreed to provide firm service shall have
priority over Shippers for whom service is provided on an interruptible
basis. If capacity is unavailable to provide gathering service for all
firm quantities nominated, then available capacity shall be allocated pro
rata on the basis of Point of Delivery Quantity separately in each
gathering system where capacity is less than firm nominations.
Shippers for whom Transporter has agreed to provide interruptible
service shall have priority according to the rate paid for gathering
service. If capacity must be allocated between interruptible Shippers for
any reason, quantities for the Shipper paying the highest rate shall be
scheduled first, quantities for the Shipper paying the second highest rate
shall be scheduled second, etc., until all available capacity has been
scheduled. In the event that two or more Shippers are paying the same rate
and capacity must be allocated between them, such allocation will be done
pro rata on the basis of nominations.
4.2 Protection of Life and Property. Transporter and Shipper shall
-------------------------------
collaborate in making receipt or Delivery adjustments, if possible, which
may be necessary to avoid or forestall injury to life or property.
4.3 Liability for Interruption. If service under this Agreement is
--------------------------
interrupted, Transporter shall not be liable for damages resulting from the
implementation of the procedures described herein, except to the extent
that such interruption of gathering is shown to be the result of gross
negligence or gross misfeasance by Transporter.
ARTICLE 5 - TERMINATION
- -----------------------
5.1 Termination Obligation. Termination of this Agreement shall not
----------------------
relieve Transporter and Shipper of the obligation under Article 2 to
correct any imbalances hereunder, or Shipper of the obligation to pay money
due hereunder to Transporter.
ARTICLE 6 - OTHER OPERATING PROVISIONS
- --------------------------------------
6.1 Monthly Nominations. The following monthly nomination procedures
-------------------
shall apply. Prior to the initiation of service hereunder, and prior to
the first Day of each Month thereafter, Shipper shall provide Transporter
with a written schedule showing its best estimate of daily Dth to be
Tendered to Transporter at each Point of Receipt and the Dth to be Tendered
to Shipper by Transporter at each Point of Delivery during the next
succeeding Month. Nominations shall be sent by facsimile or electronically
to the attention of Transporter's Volume Management/Gathering Department on
or before the time and day provided in Transporter's then-effective tariff
for the submittal of first-of-the-month nominations under Rate Schedule
TI-1.
6.2 Daily Nominations. Unless otherwise agreed, Shipper or its agent
-----------------
shall make daily nominations by facsimile or electronically to Transporter
to verify any changes in Dth which Shipper intends to Tender at the Points
of Receipt or Delivery. Such nominations shall be made to Transporter's
Volume Management/Gathering Department on or before the time and day
provided in Transporter's then-effective tariff for daily nominations under
Rate Schedule TI-1. Nominations shall include both anticipated Dth at
Point(s) of Receipt and Dth to be Delivered by Transporter at Point(s) of
Delivery. Nominations shall be for operational planning purposes only.
Transporter is not responsible for assuring that the nominated quantities
are actually Tendered by any third party at the Point(s) of Receipt.
6.3 Allocation of Interests. Prior to initial Tender at the Point(s)
-----------------------
of Receipt and as often as changes occur thereafter, Shipper or Shipper's
designee shall identify the working interest owners and shall provide
Transporter with the Dth for each owner for all Points of Receipt. Such
Dth shall be confirmed with the well operator and shall be the basin of
Transporter's allocation of gas from each Point of Receipt pursuant to
service hereunder. In the event that the well operator does not provide
confirmation for allocation of gas, such allocation will be pro rata based
on nominations.
6.4 Creditworthiness. Transporter shall not be required to commence
----------------
service or to continue to perform service for any Shipper who fails to
demonstrate creditworthiness an reasonably determined by Transporter.
Transporter's determination of creditworthiness shall be based upon a
review of Shipper's financial statements, bank references, trade
references, and such other information relating to Shipper's financial
status, obligation payment history, and other relevant factors as may be
necessary to satisfy Transporter that Shipper is creditworthy. Upon
Shipper's request, Transporter shall provide a written explanation of any
credit limitation applied to Shipper. Transporter may require Shipper to
deposit with Transporter and maintain on prepaid account, or to establish
and maintain in an escrow account, an amount equal to Transporter's
estimate of three Months of the charges for performing such service.
Alternatively, Transporter may require Shipper to furnish, within 15 Days,
good and sufficient security, as determined solely by Transporter, of a
continuing nature and in an amount equal to Transporter's estimate of three
months of charges for performing said service, or may require such other
measures as Transporter deems appropriate. Transporter may, without
waiving any rights or remedies it may have, suspend further service until
such acceptable security is received by Transporter. Upon Shipper's
establishment of an acceptable credit record or upon expiration of the
Agreement, Transporter shall refund Shipper's deposit with interest accrued
at rates set pursuant to 18 CFR Section 154.67.
6.5 Planning Information. Transporter may request planning
--------------------
information as needed from time to time and Shipper shall comply with all
reasonable requests.
6.6 Minimum Receipt Quantity. Receipt Quantities Tendered must be
------------------------
sufficient to operate Transporter's facilities.
6.7 Right-of-Way. Shipper grants, conveys, assigns, and delivers to
------------
Transporter such rights as it may have to construct and maintain pipelines
and gathering lines on the leasehold or leaseholds from which the gas
transported under this Agreement is produced. Any rights conveyed by
Shipper to Transporter pursuant to this Agreement shall not terminate at
the termination of this Agreement.
ARTICLE 7 - PRESSURE
- --------------------
7.1 Pressure at the Point(s) of Receipt. Shipper shall cause the gas
-----------------------------------
to be Tendered at the Point(s) of Receipt at a pressure sufficient to enter
Transporter's gathering system, provided Shipper shall not, except with the
agreement of Transporter, be permitted to Tender the gas at any Point of
Receipt at a pressure in excess of the maximum allowable operating pressure
of Transporter's facilities.
7.2 Pressure at the Point(s) of Delivery. Transporter shall cause
-------------------------------------
the gas to be Delivered at the Point(s) of Delivery hereunder into the
receiving pipeline facilities against the pressures prevailing from time to
time. Transporter, however, shall not be required to Deliver gas at
pressures in excess of those specified for each Point of Delivery as set
forth in Exhibit "B" of the Agreement, nor shall Transporter be required to
install facilities or operate in a manner which Transporter deems
unacceptable in order to achieve sufficient pressure to enter the receiving
party's facilities.
ARTICLE 8 - QUALITY SPECIFICATIONS.
- ----------------------------------
8.1 Specifications. Unless otherwise agreed, Shipper warrants that
--------------
all gas Tendered hereunder at each Point of Receipt and Point of Delivery
shall comply with the following quality specifications:
(a) At a pressure of 14.73 p.s.i.a. and a temperature of 60
degrees Fahrenheit, such gas shall not contain more than:
(i) .25 grain of hydrogen sulphide per 100 cubic feet,
(ii) 5 grains of total sulphur per 100 cubic feet,
(iii) 10 parts per million (0.001 percent) by volume of
oxygen and each Party shall use every reasonable effort to keep such gas
entirely free from oxygen,
(iv) 3.0 percent by volume of carbon dioxide,
(v) 7 pounds of water vapor per million cubic feet at
Points of Receipt and Points of Delivery within the states of Kansas,
Oklahoma, and Texas and 5 pounds of water vapor per million cubic feet in
all other states.
(b) Such gas shall be commercial in quality and shall be free
from any foreign material such as solids, sand, dirt, dust, gums, salt,
crude oil, water or hydrocarbons in the liquid phase, iron particles, and
other objectionable substances, including but not limited to,
polychlorinated environment, which may be injurious to pipelines, people,
property, or the environment, which may interfere with its gathering or
makes the gas unmarketable or unacceptable for delivery from Transporter's
gathering facilities.
(c) At a pressure of 14.73 p.s.i.a. the Gross Heating Value of
such as shall not be less than 968 Btus per cubic foot.
(d) The temperature of such gas shall not exceed 120 degrees
Fahrenheit; provided, however, if Transporter is required to dehydrate the
gas at the Point(s) of Receipt, then the temperature of such gas shall not
exceed 90 degrees Fahrenheit.
(e) The hydrocarbon dew point of such gas shall not exceed a
temperature of 25 degrees Fahrenheit at the maximum pressure specified in
the Agreement, or the pressure existing at the Point of Receipt or Point of
Delivery, if higher.
Notwithstanding the above, unless otherwise agreed by Transporter
in writing, Transporter shall not be required to receive gas at any Point
of Receipt which is of a quality inferior to that required by Shipper or a
third party at any Point of Delivery under the Agreement. Transporter
shall not be liable to Shipper or a third party for any damages incurred as
a result of Transporter's refusal to receive gas as a result of this
provision.
8.2 Quality Tests. The Party operating the measuring equipment,
-------------
using approved standard methods in general use in the gas industry, shall
cause adequate tests to be made to determine the quality of the gas
delivered hereunder. Such tests shall be made at intervals frequently
enough to ensure that the gas conforms to the specifications hereof.
8.3 Gross Heating Value Determinations. The measuring Party shall
----------------------------------
determine or cause to be determined the monthly Gross Heating Value of gas
delivered hereunder. The required recording facilities or sampling devices
shall be located at the Point(s) of Receipt or Point(s) of Delivery.
Unless otherwise mutually agreed, the following criteria shall apply:
(a) If the average daily measured quantity of gas is, or is
expected to be, 5,000 Dth or greater, a recording calorimeter,
chromatograph, or other mutually agreeable equipment shall be utilized;
(b) If the average daily measured quantity of gas is less than
5,000 Dth but greater than 1,000 Dth, or if the measured quantity is
attributed to more than one well, a continuous sampler shall be utilized;
and
(c) If the average daily measured quantity of gas is no greater
than 1,000 Dth and is attributed to a single well, a spot sample shall be
utilized and shall be taken at 12-month intervals, or more frequently, if
necessary.
For (b) and (c) above, the gas samples shall be analyzed in
mutually agreeable laboratory facilities and the Gross Heating Value
determined by component analysis. Other than as provided above, the
nonmeasuring Party shall have the right, upon written request, to have the
measuring Party install, maintain, and operate a recording calorimeter or
continuous sampler, in which event the nonmeasuring Party shall reimburse
the measuring Party for the cost of acquiring and installing the requested
facilities.
8.4 Verification and Retesting. The nontesting Party shall have the
--------------------------
right upon written request to witness any test or Gross Heating Value
determination, to inspect any equipment used, to obtain all relevant
results, and to request a retest or redetermination. In the event a retest
or redetermination is requested and the results, for the questioned portion
thereof, vary less than 2 percent from the previous test, the retesting
Party may recover from the requesting Party the actual costs of performing
such retest or redetermination.
8.5 Nonspecification Gas. In the event that gas Tendered hereunder
--------------------
fails to meet the specifications of Section 8.1 above, the measuring Party
shall notify the other Party of such failure. The receiving Party may
refuse to accept such gas. The Party Tendering nonspecification gas,
including, but not limited to, gas containing objectionable substances,
shall indemnify the receiving Party for any injury, damage, loss, or
liability caused by such nonspecification gas, except to the extent the
receiving Party knowingly and willingly accepts such nonspecification gas.
ARTICLE 9 - MEASUREMENT
- -----------------------
9.1 Measurement Facilities. Unless otherwise agreed, gas received
----------------------
hereunder shall be measured by orifice meters to be installed and operated
or caused to be installed and operated by Transporter at or near each Point
of Receipt and at or near each Point of Delivery. However, if adequate
measurement facilities are already in existence at any such Point of
Receipt or Point of Delivery, such existing facilities shall be used.
Measurement responsibilities at Point(s) of Receipt and Point(s) of
Delivery shall be specified in the Agreement.
If the meter(s) measuring the quantities of gas received by
Transporter at the Point(s) of Receipt also measures other quantities of
gas, the quantities of gas received for gathering shall be determined by
procedures established in Section 6.3. If the meter(s) measuring the
quantities of gas Delivered by Transporter for Shipper's account at the
Point(s) of Delivery also measures other quantities of gas, the quantities
of gas delivered after gathering shall be determined by the allocations at
the Point of Delivery on the downstream pipeline.
All orifice meters shall be installed and operated in accordance
with the specifications prescribed in AGA Report No. 3, entitled "Orifice
Metering of Natural Gas" including any appendices and any existing or
subsequent revisions or amendments thereto. The unit of measurement for
gas delivered hereunder shall be 1 Dth, as defined in Article 1 hereof.
Unless otherwise stated, all quantities are to be specified in terms of
such unit. The average atmospheric pressure at each Point of Receipt or
Point of Delivery shall be determined by the measuring Party.
9.2 Measurement Specifications. The quantities of gas measured
--------------------------
hereunder shall be computed in accordance with the specifications
prescribed in said AGA Report No. 3. Factors required in the computations
to be made in accordance with said AGA Report No. 3 shall be determined
from the following information:
(a) The temperature of the gas flowing through each meter shall
be determined by the use of a recording thermometer and the arithmetical
average of the temperatures so recorded during the time gas was flowing
shall be used in computing measurements.
(b) The specific gravity of the gas shall be determined every 6
Months by the Party operating the meter, or more frequently if found
necessary in practice at each meter, in accordance with an approved method
commonly accepted in the gas industry. The regular test shall determine
the specific gravity to be used in computations in the measurement of gas
deliveries until the next regular test, or until changed by special test.
(c) The Reynolds Number and Expansion Factor for wellhead
measurement may be assumed to be 1.0 irrespective of the actual value of
these factors. In all instances other than wellhead measurement, the
Reynolds Number and Expansion Factor shall be determined for each meter for
each chart cycle. The average differential and static pressures recorded
by each meter, each chart cycle, shall determine the value of these factors
to be used in computing measurements.
(d) Deviation from Bovle's Law shall be determined in accordance
with the American Gas Association NX-19 formula or AGA Report No. 8, where
applicable. The arithmetic average of the pressure and temperature recorded
during the time gas was flowing shall be used in the computations. The
pressure and temperature data shall be used in conjunction with data
obtained from a compositional analysis of the gas which shall be verified
at least once each year, or more frequently if found necessary in practice.
9.3 Calibration of Equipment. At least once each 3 Months the
------------------------
measuring equipment, including temperature recorders, is to be calibrated,
and adjusted if necessary, by the owning Party in the presence of a
representative of the other Party, if such other Party chooses to be
represented.
If either Party at any time desires a special test of any
measuring equipment, it will promptly notify the other Party, and the
Parties will then cooperate to promptly secure a calibration test and a
joint observation of any adjustments.
9.4 Testing. Each Party shall give to the other notice of the time
-------
of all regular tests of measuring equipment and other tests called for
herein sufficiently in advance of the holding of tests so that the other
Party may conveniently have its representative present. If, upon any test,
the quantity measured by any measuring equipment is found to be inaccurate
by 1.0 percent or more, registrations thereof shall be corrected at the
rate of such inaccuracy for any period which is definitely known and agreed
upon, but in case the period is not definitely known and agreed upon, then
for a period extending back one-half of the time elapsed since the last
date of calibration. Following any test, measuring equipment found
inaccurate shall be promptly adjusted to record as accurately as possible.
If for any reason measuring equipment is out of service and/or out of
repair so that the amount of gas received or delivered cannot be measured
or computed from the reading thereof, the gas received or delivered during
the period such measuring equipment is out of service and/or out of repair
shall be estimated and agreed upon by the Parties hereto upon the basis of
the best data available, using the first of the following methods which is
feasible:
(a) By correcting the error, if the percentage of error is
ascertainable by calibration, test, or mathematical calculation.
(b) By using the registration of any check measuring equipment,
if installed and accurately registering.
(c) By estimating the quantities received or delivered based on
quantities during periods of similar operating conditions when the
measuring equipment was registering accurately.
9.5 Check Meters. Either Party hereto may, at its option and
------------
expense, install and operate check meters to check the other Party's
measuring equipment, but measurements of gas for the purpose of this
Agreement shall be by means of the measuring equipment identified in this
Article, provided Shipper shall not install check meters on Transporter's
facilities. Check meters, if installed, shall be installed, operated, and
maintained in accordance with the specifications prescribed in this Article
9. Either Party's check meters shall be subject at all reasonable times to
inspection and examination by the other, but the reading, calibration and
adjustment thereof, and changing of charts shall be done only by the Party
installing same.
9.6 Measurement Review. Each Party hereto shall, upon request,
------------------
furnish to the other Party at the earliest practicable time all charts and
records of electronic measurement upon which it has based any statements of
gas received or delivered. Such charts or records of electronic measurement
shall be returned to the providing Party within a 30-Day period. Each
Party shall have access to the other Party's records and books at all
reasonable hours so far as they affect measurement and settlement
hereunder.
9.7 Electronic Flow Computers. It is recognized that electronic or
-------------------------
other types of flow computers have been developed that permit the direct
computation of gas flows without the use of charts. Additionally, the use
of on-line gas chromatograph for Btu and specific gravity determinations
can be used in conjunction with electronic flow computers. Where the
substitution of these devices is deemed acceptable by Transporter, their
use for the measurement required herein will be permitted.
9.8 New Measurement Techniques. If, at any time during the term
--------------------------
hereof, a new method or technique is developed with respect to gas
measurement or the determination of the factors used in such gas
measurement, such new method or technique may be substituted by
Transporter. Transporter shall promptly inform Shipper of any new
technique adopted.
ARTICLE 10 - BILLING AND PAYMENT
- --------------------------------
10.1 Statement by Transporter. On or before the last Day of each
------------------------
Month, Transporter shall submit to Shipper a statement setting forth
information relevant to the transaction under the Agreement during the
preceding Month, including the volume and Thermal Content delivered by
Transportar at the Point(s) of Delivery.
10.2 Statement by Shipper. Where Shipper operates the measurement
-------------------
facilities or where a third party is delivering gas for the account of
Shipper, Shipper or its agent shall submit to Transporter on or before the
5th business Day of each Month, a statement in reasonable detail setting
forth the volume and Thermal Content of gas delivered to Transporter at the
Point(s) of Receipt during the preceding Month. Where Shipper or its agent
is delivering quantities for Shipper's account and the account of third
parties, Shipper or its agent shall provide Transporter and such third
parties, at the time Shipper nominates under Article 6, with the necessary
allocations required to properly account for the quantities delivered to
Transporter.
10.3 Invoice and Payment. Each Month Transporter shall invoice
-------------------
Shipper for the charges payable by Shipper for services provided during the
preceding Month. Billing of the gathering Commodity Charge shall be on Dth
received by Transporter at Point(s) of Receipt. Shipper shall pay
Transporter such charges within 10 Days of the invoice date. Should
Shipper fail to pay all invoiced amounts when due, Shipper shall pay
Transporter a late charge on the unpaid balance. Such late charge shall
accrue on each Day from the due date at a rate of interest equal to that
specified pursuant to 18 CFR Section 154.67 and compounded quarterly. If
either principal or late charges become delinquent, any subsequent payments
received shall first be applied to the late charges due, then to the
previously outstanding principal due, and lastly, to the most current
principal due. Any unpaid late charges will be added to the outstanding
principal balance for future late charge determination. Subject to
requirements of regulatory bodies having jurisdiction and without prejudice
to any other rights and remedies available to Transporter under the law and
this Agreement, Transporter shall have the right, but not the obligation,
to discontiunue service hereunder if any charges remain unpaid for 30 Days
after the due date thereof. Gathering of gas shall be resumed upon payment
by Shipper of such unpaid charges.
10.4 Estimates. At the request of either Party, the other Party will
---------
furnish an estimate by the 10th Day of each Month of billing and payment
data applicable to the preceding Month. In the absence of actual data,
such estimate may be used as the basis for invoice and payment. Any
difference between actual data and estimated data shall be adjusted in the
next Month.
10.5 Corrections. If an error is discovered in any statement
-----------
submitted, the Party discovering the error shall give notice thereof to the
other Party promptly after discovery. The error shall be correctted within
30 Days after the amount thereof has been confirmed between the Parties. No
corrections shall be made for any error unless the Party gives notice
thereof within 24 Months after the error was comitted.
ARTICLE 11 - FORCE MAJEURE
- --------------------------
11.1 Force Majeure. In the event of either Party's being rendered,
-------------
wholly or in part by force majeure, unable to carry out its obligations
under the Agreement, it is agreed that when such Party gives notice and
full particulars of such force majeure, in writing or by telephone, to the
other Party which shall be done as soon as practicable after the occurrence
of the causes relied on, then the obligations of the Parties hereto, other
than its obligation to make payments of amounts due hereunder, so far as
they are affected by such force majeure, shall be suspended during the
continuance of any inability so caused, but for no longer period, and such
cause shall, so far as possible, be remedied with all reasonable dispatch.
However, if quantities of Shipper's gas are destroyed by an event of force
majeure while in Transporter's possession, the obligations of the Parties
under the Agreement shall terminate with respect to the quantities lost.
The term "force majeure" as employed herein shall include, but shall
not be limited to, the inability of Shipper to transport gas downstream of
the Point of Delivery under an interruptible transportation agreement, acts
of God, strikes, lockouts or other industrial disturbances, acts of the
public enemy or terrorists, wars, blockades, insurrections, riots,
epidemics, landslides, lightning, earthquakes, fires, storms, floods,
washouts, pipeline freezing, arrest and restraint of rulers and peoples,
civil disturbances, explosions, breakage or accident to machinery or lines
of pipe, sudden partial or sudden entire failure of wells, failure to
obtain materials and supplies due to goverrmental regulations, and causes
of like or similar kind, whether herein enumerated or not, and not within
the control of the Party claiming suspension, and which by the exercise of
due diligence such Party is unable to overcome; provided that the exercise
of due diligence shall not require settlement of labor disputes against the
better judgment of the Party having the dispute. The term "force majeure"
as employed herein shall also include, but shall not be limited to,
inability to obtain or acquire at reasonable cost, grants, servitudes,
rights-of-way, permits, licenses, or any other authorizations from third
parties or agencies (private or govermental) or inability to obtain or
acquire at reasonable cost necessary materials or supplies to construct,
maintain, and operate any facilities required for the performance of any
obligations under the Agreement, when any such inability directly or
indirectly contributes to or results in either Party's inability to perform
its obligations. In events of force majeure, Transporter's responsibility
will be limited to taking reasonable and prudent actions to eliminate or
remedy such circumstances, and Transporter shall have no liability for any
losses occasioned by events of force majeure.
ARTICLE 12 - INTERRUPTIONS OF SERVICE
- -------------------------------------
12.1 Alterations and Repairs. Transporter shall have the right,
-----------------------
without liability to Shipper, to interrupt the gathering of gas for
Shipper, when necessary to test, alter. modify, enlarge, or repair any
facility or property comprising a part of, or appurtenant to, its system,
or otherwise related to the operation thereof. Transporter shall endeavor
to cause a minimum of inconvenience to Shipper. Except in cases of
unforeseen emergency, Transporter shall give advance notice to Shipper of
its intention to interrupt the gathering of gas, stating the anticipated
timing and magnitude of each such interruption.
ARTICLE 13 - TAXES
- ------------------
13.1 Taxes. All production (including ad valorem-type production
-----
taxes), gathering, delivery, sales, severance, or other excise taxes or
assessments upon the gas produced and delivered hereunder by Shipper to
Transporter, which are now or hereafter in existence or authorized for
collection by any state or other governmental agency or duly constituted
authority, either directly or indirectly, shall be paid or caused to be
paid by Shipper.
ARTICLE 14 - LIABILITY
- ----------------------
14.1 Liability. Subject to the provisions of Sections 4.3, 11.1, and
---------
16.1, each Party assumes full responsibility and liability arising from the
installation, ownership, and operation of its pipelines and facilities and
will hold the other Party harmless from any claim, loss, expense, or
liability (except as otherwise specifically provided in this Agreement)
that such Party incurs on account of such installation, ownership, and
operation. However, one Party will not be liable to the other Party for, or
hold the other Party harmless from, any claims, loss, expense, or liability
arising out of acts or omissions of third parties when such acts or
omissions are not reasonably within the first Party's control.
ARTICLE 15 - WARRANTY
- ---------------------
15.1 Warranty. Each Party warrants that the title to, and right to
--------
possession of, all gas delivered to the other Party hereunder will at the
time of delivery be free from all liens and adverse claims, and each Party
shall indemnify the other Party against all damages, costs, and expenses of
any nature whatsoever arising from every claim against said gas.
ARTICLE 16 - RESPONSIBILITY FOR GAS AND PRODUCTS
- ------------------------------------------------
16.1 Responsibility for Gas. Shipper shall be in exclusive control
----------------------
and possession of the gas until such has been received by Transporter at
the Point(s) of Receipt and after such gas has been Delivered by
Transporter at the Point(s) of Delivery. Transporter shall be in exclusive
control and possession of such gas while it is in Transporter's possession.
Subject to the provisions of Sections 4.3, 11.1, and 14.1, the Party which
is or is deemed to be in exclusive control and possession of such gas shall
be responsible for all injury, damage, loss, or liability caused thereby.
Provided, however, that Transporter's responsibility with respect to
Shipper's gas shall be deemed to be met if Transporter exercises ordinary
care in protecting such gas.
16.2 Responsibility for Products. Unless otherwise agreed,
---------------------------
Transporter may process or cause to be processed for the removal of
Products any gas received prior to the Delivery of same. Transporter
shall nonetheless remain obligated to Deliver gas at the Point(s) of
Delivery which has the saw Thermal Content as that of the Receipt Quantity
(lease fuel reimbursement). Unless otherwise agreed, Shipper shall have no
further rights with respect to Products obtained by Transporter from the
gas while the gas is in Transporter's possession. Unless otherwise agreed,
title to all such Products shall vest in Transporter, and Shipper shall
indemnify Transporter against all damages, costs, and expenses of any
nature whatsoever arising from every claim against said Products or the
right to payment for same. If Shipper enters into a separate agreement for
processing of Shipper's gas gathered under this Agreement, Shipper also
shall enter into separate agreements with Transporter for gathering and
transportation of Shipper's liquefiable gas to the processing plant.
ARTICLE 17 - WAIVER
- -------------------
17.1 Waiver. The failure of either Party hereto at any time to
------
require performance by the other Party of any provision of the Agreement
shall in no way affect the right of such Party thereafter to enforce the
same, nor shall the waiver by either Party of any breach of any provision
hereof by the other Party be taken or held to be a waiver by such Party of
any succeeding breach of such provision, or as a waiver of the provision
itself.
ARTICLE 18 - LIMITATION OF SERVICE
- ----------------------------------
18.1 Limitation of Service. Transporter shall not be required to
---------------------
perform service under the Agreement on behalf of any Shipper that fails to
substantially comply with any and all of the terms and conditions of the
Agreement.
ARTICLE 19 - AMENDMENT
- ----------------------
19.1 Amendment. The Agreement shall be amended only by an instrument
---------
in writing executed by both Parties in writing.
ARTICLE 20 - MISCELLANEOUS
- --------------------------
20.1 Headings. The headings contained in this Agreement and in the
--------
General Terms and Conditions - Gathering are for reference purposes only
and shall not affect the meaning or interpretation of this Agreement.
20.2 Applicable Law. This Agreement shall be interpreted according
--------------
to the laws of the State of Colorado, notwithstanding any conflict of laws
principles which may require the application of the laws of another
jurisdiction.
ARTICLE 21 - ASSIGNMENT
- -----------------------
21.1 Assignable Parties. Except as provided under Article 6, this
------------------
Agreement may be assigned by either of the Parties to:
(a) any person, firm, or corporation acquiring all, or
substantially all, of the natural gas business of said Party;
(b) a trustee or trustees, individual or corporate, as security
for bonds or other obligations or securities; but it may not be otherwise
assigned without the consent of the other Party hereto. Whenever any
corporation is referred to herein, such reference shall be deemed to
include the successors and assignees of such corporation.
21.2 Assignment. This Agreement shall be binding upon and inure to
----------
the benefit of the successors and assignees of each of the Parties hereto.
21.3 Clarification of Use. Unless expressly allowed by Transporter
--------------------
in writing, gathering for other than the purposes expressly stated in the
Agreement shall not be provided.
<PAGE>
EXHIBIT "B"
to
GAS GATHERING AGREEMENT - INTERRUPTIBLE
between
COLORADO INTERSTATE GAS COMPANY (Transporter)
and
MESA OPERATING LIMITED PARTNERSHIP (Shipper)
DATE: October 1, 1993
---------------
Point(s) of Receipt Well Name
------------------- ---------
All Points Listed on the attached All wells listed on the attached
"Master List of Gathering Receipt "Master List of Gathering Receipt
Points" which are upstream of the Points" which are upstream of the
Points of Delivery listed below Points of Delivery listed below,
which is updated automatically
with new well connections and
disconnections
Maximum
Pressure Measuring
Point(s) of Delivery (p.s.i.g.) Party Meter Number
- -------------------- ---------- --------- ------------
Lakin Master Meter 900 Transporter CDP065864000
Sec.29, T24S, R36W
Kearny County, KS
H&P Sunflower 500 Transporter CDP991652000
Sec. 29, T25S, R35W
Kearny County, KS
Hugoton K N Exchange 240 Transporter INT991181000
Sec. 13, T25S, R36W
Kearny County, KS
<PAGE>
EXHIBIT "B"
SCHEDULE 1
POINTS OF RECIEPT, SHIPPER-OWNED GAS AND SHIPPER-OPERATED GAS
AMENDMENT DATED January 1, 1994
to
GAS GATHERING AGREEMENT - INTERRUPTIBLE
DATED October 1, 1993
between
COLORADO INTERSTATE GAS COMPANY
and
MESA OPERATING CO.
ACTING ON BEHALF OF ITSELF AND AS AGENT FOR
HUGOTON CAPITAL LIMITED PARTNERSHIP
<TABLE>
Maximum
Pressure Measuring Location
Point(s) of Receipt Well Name (Note 1) Party Number
- ------------------- --------------------------- -------- ---------- ------------
<S> <C> <C> <C> <C>
Stanton County, KS:
- ------------------
Sec. 22, T27S, R40W Collingwood, A.J.1 (Note 4) (Note 2) (Note 3) CMP026790111
Collingwood 9-22 (Note 4) (Note 2) (Note 3) CMP026718111
Wilson 1-22 (Note 4) (Note 2) (Note 3) CMP097912111
Sec. 32, T27S, R40W Cross J. L. 2 (Note 4) (Note 2) (Note 3) CMP028390111
Cross 3-32 (Note 4) (Note 2) (Note 3) CMP028395111
Sec. 30, T27S, R40W Fraser, Nellie 1 (Note 4) (Note 2) (Note 3) CMP036270111
Sec. 6, T28S, R40W Floyd 3-9 (Note 4) (Note 2) (Note 3) CMP035722111
Sec. 34, T27S, R40W Mohney, Eugene 1 (Note 4) (Note 2) (Note 3) CMP070760111
Mohney, E. 2-34 (Note 4) (Note 2) (Note 3) CMP070761111
Mohney, E. 3-34 (Note 4) (Note 2) (Note 3) CMP070812111
Sec. 26, T27S, R40W Smith, Abbie E 1 (Note 4) (Note 2) (Note 3) CMP086010111
Smith, A. E. 2-26 (Note 4) (Note 2) (Note 3) CMP086011111
Smith, A. E. 3-26 (Note 4) (Note 2) (Note 3) CMP086012111
Sec. 27, T27S, R40W Timm R. K. 1 (Note 4) (Note 2) (Note 3) CMP093200111
Timm 2-27 (Note 4) (Note 2) (Note 3) CMP093205111
Winger, C. 7-27 (Note 4) (Note 2) (Note 3) CMP098262111
Sec. 29, T27S, R40W Williamson, Mary C.1(Note 4)(Note 2) (Note 3) CMP097810111
Williamson 2-29 (Note 4) (Note 2) (Note 3) CMP097811111
Sec. 33, T27S, R40W Winger, Clarence 1 (Note 4) (Note 2) (Note 3) CMP098060111
Winger, C. 10-33 (Note 4) (Note 2) (Note 3) CMP098265111
Winger, C. 12-33 (Note 4) (Note 2) (Note 3) CMP098267111
Sec. 28, T27S, R40W Winger, Clarence 2 (Note 4) (Note 2) (Note 3) CMP098110111
Winger, C. 9-28 (Note 4) (Note 2) (Note 3) CMP098264111
Winger, C. 13-28 (Note 4) (Note 2) (Note 3) CMP098268111
Sec. 21, T27S, R40W Winger, Clarence 4 (Note 4) (Note 2) (Note 3) CMP098210111
Winger, C. 8-21 (Note 4) (Note 2) (Note 3) CMP098263111
Winger, C. 15-21 (Note 4) (Note 2) (Note 3) CMP098270111
Sec. 35, T27S, R40W Winger, Clarence 5 (Note 4) (Note 2) (Note 3) CMP098260111
Winger, C. 6-35 (Note 4) (Note 2) (Note 3) CMP098261111
Winger, C. 16-35 (Note 4) (Note 2) (Note 3) CMP098271111
Sec. 23, T27S, R40W Winger, T. R. 1 (Note 4) (Note 2) (Note 3) CMP098310111
Winger, T. R. 2-23 (Note 4) (Note 2) (Note 3) CMP098311111
Winger, T. R. 3-23 (Note 4) (Note 2) (Note 3) CMP098312111
Sec. 16, T27S, R40W Baughman 3-16 (Note 3) CMP006980111
Baughman 2 (Note 3) CMP006970111
Sec. 5, T28S, R40W Baughman 6-16 (Note 3) CMP006990111
Sec. 8, T28S, R40W Cooper, E. D. 1 (Note 3) CMP027090111
Sec. 9, T28S, R40W Floyd, Eugene 1 (Note 3) CMP035720111
Floyd 2-9 (Note 3) CMP035721111
Sec. 4, T28S, R40W Winger, Clarence 3 (Note 3) CMP098160111
Winger, C. 11-4 (Note 3) CMP098266111
Winger 14-4 (Note 3) CMP098269111
Hamilton County, KS:
- -------------------
Sec. 5, T26S, R39W Akers, Barney 1 (Note 3) CMP001630111
Akers, Barney 2-5 (Note 3) CMP001631111
Sec. 9, T26S, R39W Brothers I.S. #1 (Note 3) CMP020620111
Brothers 4-9 (Note 3) CMP020700111
Brothers 5-9 (Note 3) CMP020710111
Sec. 3, T26S, R39W Brothers 2-A (Note 3) CMP020690111
Brothers 3-3 (Note 3) CMP020600111
Brothers 4-3 (Note 3) CMP020705111
Sec. 10, T26S, R39W Federal Farm Mortgage 1-10 (Note 3) CMP033758111
Lampe, John 1 (Note 3) CMP054990111
Sec. 36, T25S, R39W Fields, R. S. 1-36 (Note 3) CMP035100111
Yingling, Effie R-1 (Note 3) CMP099850111
Yingling 2-36 (Note 3) CMP099853111
Sec. 36, T26S, R40W Heltemes 1-36 (Note 3) CMP044140111
Heltemes, N. A. 2 (Note 3) CMP044210111
Heltemes 8-36 (Note 3) CMP044147111
Sec. 20, T26S, R39W Frease, E.M. 1 (Note 3) CMP036420111
Frease, E.M. 2-20 (Note 3) CMP036421111
Frease, E.M. 4-20 (Note 3) CMP036423111
Sec. 25, T25S, R39W Frease, E. M. 3-25 (Note 3) CMP036422111
Sec. 30, T26S, R39W Hattrup, L. J. 1 (Note 3) CMP043310111
Hattrup 2-30 (Note 3) CMP043290111
Hattrup 3-30 (Note 3) CMP043295111
Sec. 19, T26S, R39W Heltemes, N. A. 1 (Note 3) CMP044160111
Heltemes 4-19 (Note 3) CMP044143111
Heltemes 6-19 (Note 3) CMP044145111
Sec. 25, T26S, R40W Heltemes 5-25 (Note 3) CMP044144111
Heltemes N. A. 3 (Note 3) CMP044260111
Heltemes 7-25 (Note 3) CMP044146111
Sec. 16, T26S, R39W Hoffman, C. A. 1 (Note 3) CMP046460111
Hoffman, C. A. 2-16 (Note 3) CMP046340111
Hoffman 3-16 (Note 3) CMP046345111
Sec. 8, T26S, R39W Lampe 1 (Note 3) CMP054940111
Lampe 2-8 (Note 3) CMP054900111
Sec. 10, T26S, R39W Lampe 2-10 (Note 3) CMP054995111
Sec. 7, T26S, R39W Mesa-Lowenberg 1-7 (Note 3) CMP068570111
Sec. 4, T26S, R39W Rector, Oscar 1 (Note 3) CMP078930111
Rector 2-4 (Note 3) CMP078929111
Rector 3-4 (Note 3) CMP078928111
Hugoton Field:
- -------------
Sec. 17, T26S, R39W Stucky, Martin 1 (Note 3) CMP091650111
Stucky 2-17 (Note 3) CMP091651111
Stucky 3-17 (Note 3) CMP091415111
Haskell County, KS:
- ------------------
Sec. 36, T30S, R32W Bird A-1 Transporter CMP008820111
Sec. 6, T29S, R34W Burton -1 Transporter CMP021770111
Burton A-2 Transporter CMP021780111
Burton A-3 Transporter CMP021781111
Sec. 33, T28S, R34W Eubank, M. H. 1 (Note 5) Transporter CMP032270111
Eubank 2-33 (Note 5) Transporter CMP032175111
Sec. 28, T28S, R34W Eubank, M. H. A-1 (Note 5) Transporter CMP032020111
Eubank, M. H. A-2 (Note 5) Transporter CMP032365111
Sec. 23, T28S, R34W Eubank, M. HB-1 Transporter CMP032120111
Eubank, M. H. B-2 Transporter CMP032366111
Sec. 7, T28S, R34W Eubank, M. H. C-1 Transporter CMP032170111
Eubank C-5 Transporter CMP032174111
Sec. 30, T28S, R34W Green C-1 Transporter CMP039630111
Sec. 30, T28S, R33W Laird B-1 Transporter CMP054690111
Green C-3 Transporter CMP039632111
Sec. 1, T29S, R34W Dennis B-2 (Note 5) Transporter CMP029465111
Sec. 1, T29S, R34W Dennis CG B-1 (Note 5) Transporter CMP029450111
Sec. 4, T29S, R34W Gregg, E. M. 1 (Note 5) Transporter CMP039930111
Gregg A-2 (Note 5) Transporter CMP039928111
Gregg A-3 (Note 5) Transporter CMP039929111
Sec. 32, T28S, R34W Gregg 8-32 (Note 5) Transporter CMP039933111
McCoy, Frank 1 (Note 5) Transporter CMP064480111
McCoy 4-32 (Note 5) Transporter CMP064495111
Sec. 2, T27S, R34W Gunnell 1 Transporter CMP040230111
Gunnell 1-A Transporter CMP040231111
Sec. 35 T27S, R34W Baughman C-3 Transporter CMP007072111
Baughman JW C-1 Transporter CMP007070111
Sec. 15, T28S, R34W Home Royalty Assn. 1 Transporter CMP046660111
Home Royalty Assn. 2 Transporter CMP046661111
Sec. 3, T28S, R34W Jones C-1 Transporter CMP051110111
Jones C-2 Transporter CMP051111111
Sec. 24, T28S, R34W Lemon A-1 Transporter CMP055390111
Sec. 25, T28S, R34W Lemon B-1 Transporter CMP055440111
Lemon A-2 Transporter CMP055391111
Lemon B-2 Transporter CMP055441111
Sec. 9, T29S, R33W Lemon C-1 (Note 5) Transporter CMP055490111
Lemon C-2 (Note 5) Transporter CMP055491111
Sec. 1, T29S, R34W Light D-1 (Note 5) Transporter CMP055960111
Sec. 3, T29S, R34W Moody C-2 (Note 5) Transporter CMP026745111
Moody C-3 (Note 5) Transporter CMP071165111
Sec. 2, T29S, R34W Onions 1 (Note 5) Transporter CMP075060111
Onions A-2 (Note 5) Transporter CMP075061111
Sec. 21, T28S, R33W Orth 1 Transporter CMP075110111
Orth A-2 Transporter CMP075115111
Sec. 30, T28S, R33W Laird B-2 Transporter CMP054691111
Laird CC B-1 Transporter CMP054690111
Sec. 31, T28S, R34W Pickens 1 Transporter CMP076760111
Pickens A-2 Transporter CMP076751111
Pickens A-3 Transporter CMP076752111
Sec. 3, T29S, R34W Rahenkamp 1 (Note 5) Transporter CMP078030111
Rahenkamp A-2 (Note 5) Transporter CMP078035111
Sec. 27, T27S, R33W Roy, Frank 3 (Note 5) Transporter CMP080070111
Roy 9-27 (Note 5) Transporter CMP080195111
Sec. 34, T27S, R33W Roy, Frank 4 (Note 5) Transporter CMP080110111
Sec. 34, T27S, R33W Roy 11-34 (Note 5) Transporter CMP080197111
Sec. 33, T27S, R33W Roy, Frank 6 (Note 5) Transporter CMP080190111
Sec. 33, T27S, R33W Roy 10-33 (Note 5) Transporter CMP080196111
Sec. 13, T30S, R32W Stevens B-1 Transporter CMP090450111
Sec. 10, T28S, R34W Stonestreet 1 Transporter CMP090870111
Stonestreet A-2 Transporter CMP090875111
Sec. 6, T29S, R33W Wheatley 1 (Note 5) Transporter CMP096810111
Wheatley 3-6 (Note 5) Transporter CMP096812111
Sec. 29, T28S, R34W Winsted 1 (Note 5) Transporter CMP098410111
Winsted 2-29 (Note 5) Transporter CMP098413111
Winsted 4-29 (Note 5) Transporter CMP098415111
Kearney County, KS:
- ------------------
Sec. 21, T24S, R38W Swank 1-A Transporter CMP091850111
Sec. 9, T24S, R38W Bakke-Wiatt 1-A Transporter CMP003340111
Sec. 17, T24S, R38W Burnett 1-A Transporter CMP021471111
Finney County, KS:
- -----------------
Sec. 32, T25S, R31W Beach 1 Transporter CMP007320111
Grant County, KS:
- ----------------
Sec. 5, T27S, R36W Jarvis 1-A Transporter CMP049361111
Jarvis 1 Transporter CMP049360111
Seward County, KS:
- -----------------
Sec. 2, T31S R32W Bird B-1 Transporter CMP008870111
</TABLE>
<TABLE>
Maximum
Pressure
Point(s) of Delivery (p.s.i.g.) Location Number
- -------------------- ---------- ---------------------
<S> <C> <C>
Lakin Master Meter 920 CDP065864000
Sec. 29, T24S, R36W
Kearny County, KS
H&P Sunflower 500 CDP991652000
Sec. 29, T25S, R35W
Kearny County, KS
Hugoton KN Exchange 240 INT9911810000
Sec. 13, T25S, R36W
Kearny County, KS
Satanta (Note 6) CDP991830000
Sec. 5, T30S, R35W
Grant County, KS
</TABLE>
<PAGE>
NOTES: (1) Delivery shall be at pressures necessary to make delivery
into Transporter's facilities against the pressures
existing therein from time to time but shall not exceed the
design pressure of such facilities.
(2) Transporter shall use its good faith efforts to operate the
Hugoton Gathering System at the Lateral Interconnections in
Stanton County, Kansas at pressures not in excess of 125
psig. In no event shall the pressure exceed 137 psig.
Transporter's pressure commitment shall be subject to
Shipper's compression on Transporter's F54-8" and/or F51-8"
laterals not causing Transporter's gathering system
pressure to exceed these limits, provided that the pressure
commitment shall apply if Shipper is compressing 7,500 Mcf
per day or less through Shipper's compression on
Transporter's F54-8" and/or F51-8" laterals. The Lateral
Interconnections are:
(a) Lateral west of the interconnect with F54-8" in
Section 33, T27S, R40W.
(b) Lateral east of the interconnect with F54-8" in
Section 33, T27S, R40W.
(c) Lateral west of the interconnect with F54-8" in
Section 28, T27S, R40W.
(d) Lateral east of the interconnect with F54-8" in
Section 33, T27S, R40W.
(e) Lateral east of the interconnect with F9-10" in
Section 21, T27S, R40W.
(f) Lateral east of the interconnect with F9-10" in
Section 15, T27S, R40W.
If the pressures at one or more of the interconnect points
described above are exceeded any time, Shipper shall
provide written notification to Transporter of such actual
pressures. Upon verification and provided that Shipper's
compression is in compliance with the limitations above,
Transporter, as soon as practicable but not more than 120
days after such notification, excluding any days of delay
in obtaining rights-of-way, shall install solely at its
cost, compression, loopline or any other facilities
necessary to achieve the required pressure at that
location. In the event that Transporter encounters a delay
or is prevented from obtaining rights-of-way, Shipper may
obtain such rights-of-way satisfactory to Transporter, and
shall assign same to Transporter, and Transporter shall
reimburse Shipper for the cost of such rights-of-way.
(3) Shipper operates Transporter's meters at Shipper's wells
upstream of the White Bear Meter Point (CDP991828000) in
Hamilton County, Kansas. Each month, Shipper's Dth from
these wells shall be determined as follows:
Gross Metered Dth at White Bear
Add: Transporter's Fuel Usage at Hugoton Field
Compressor #5
Total White Bear Dth
Less: Dth Measured by Transporter at
Transporter Operated Meter Stations
Upstream of White Bear
Calculated Shipper White Bear Dth
Less: Third Party Dth, if any, included in
Shipper Operated Measurement
Upstream of White Bear
Equals Shipper Dth at white Bear Meter Point
Shipper will furnish Transporter monthly measurement
information on each well operated by Shipper as stated in
the June 1, 1994 Letter Agreement. The location numbers for
the individual wells are listed for information only.
(4) Under the provisions of the Letter Agreement between the
Parties dated January 5, 1994, these wells behind the White
Bear Meter Point received a rate discount. Monthly billing
for the wells entitled to this discount shall be governed
by Transporter's January 17, 1994 letter described in
Footnote 2 of Appendix "A" detailing invoice procedures.
(5) Transporter shall maintain a monthly average pressure not
to exceed 85 psig at the interconnection point of
Transporter's F2617-4", F2607-4", F2606-4" and F-28-8"
gathering lines and Transporter's F1L-12" gathering
trunkline and F50-4" gathering line at the interconnect
point with Transporter's F1-16" gathering trunkline.
transporter shall install solely at its cost the necessary
pressure measuring equipment at such points and shall grant
Shipper access to the site and equipment so that Shipper
can monitor pressure. If the pressures at one or more of
the locations described above are exceeded for three
consecutive months, Shipper shall provide written
notification to Transporter of such actual pressure. Upon
verification, Transporter, as soon as practicable but not
more than 120 days after such notification, excluding any
days of delay in obtaining rights-of-way, will install
solely at its cost, compression, loopline or any other
facilities necessary to achieve the required pressures at
that location. In the event that Transporter encounters a
delay or is prevented from obtaining rights-of-way, Shipper
may obtain such rights-of-way satisfactory to Transporter,
and shall assign same to Transporter, and Transporter shall
reimburse Shipper for the cost of such rights-of-way.
(6) Transporter's maximum delivery obligation is 15,000 Mcf per
day at 100 psig. Shipper shall install, maintain and
operate its facilities to provide for a constant pressure
of 100 psig at the Point of Delivery.
<PAGE>
EXHIBIT "B"
SCHEDULE 2
POINTS OF RECEIPT, SHIPPER-NEW GAS
AMENDMENT DATED January 1, 1994
to
GAS GATHERING AGREEMENT - INTERRUPTIBLE
DATED October 1, 1993
between
COLORADO INTERSTATE GAS CO.
and
MESA OPERATING CO.
ACTING ON BEHALF OF ITSELF AND AS AGENT FOR
HUGOTON CAPITAL LIMITED PARTNERSHIP
Maximum Measuring Location
Point(s) of Receipt Well Name Pressure Party Number
- ------------------- --------- -------- --------- --------
NO GAS SUBJECT TO THIS SCHEDULE AT THIS TIME.
<PAGE>
EXHIBIT "B"
SCHEDULE 3
POINTS OF RECEIPT, SHIPPER DIRECTLY-CONNECTED GAS
AMENDMENT DATED January 1, 1994
to
GAS GATHERING AGREEMENT
DATED October 1, 1993
between
COLORADO INTERSTATE GAS CO.
and
MESA OPERATING CO.
ACTING ON BEHALF OF ITSELF AND AS AGENT FOR
HUGOTON CAPITAL LIMITED PARTNERSHIP
Maximum Measuring Location
Point(s) of Receipt Well Name Pressure Party Number
- ------------------- --------- -------- --------- --------
NO GAS SUBJECT TO THIS SCHEDULE AT THIS TIME.
<PAGE>
<TABLE>
<CAPTION>
COLORADO INTERSTATE GAS COMPANY
MASTER LIST OF GATHERING RECEIPT POINTS
AS OF 09/10/93
HUGOTON/PANOMA AREA G 2 LAM
COUNTY LOCATION
SECTION TOWNSHIP RANGE NAME STATE WELL NAME NUMBER MEASURING PARTY
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
027 023S 035W KEARNY KS STEENIS 1 090390111 COLORADO INTERSTATE GAS CO
013 030S 032W HASKELL KS STEVENS B-1 090450111 COLORADO INTERSTATE GAS CO
020 024S 036W KEARNY KS STINCHCOMB 1 090510111 COLORADO INTERSTATE GAS CO
020 024S 036W KEARNY KS STINCHCOMB 1-2-20 090511111 COLORADO INTERSTATE GAS CO
010 028S 034W HASKELL KS STONESTREET 1 090870111 COLORADO INTERSTATE GAS CO
014 029S 032W HASKELL KS STOOPS A-1 091230111 COLORADO INTERSTATE GAS CO
017 026S 039W HAMILTON KS STUCKEY 3-17 091415111 COLORADO INTERSTATE GAS CO
029 028S 034W HASKELL KS STUCKY LAN 2-29 091410111 COLORADO INTERSTATE GAS CO
017 026S 039W HAMILTON KS STUCKY M 1 091650111 COLORADO INTERSTATE GAS CO
017 026S 039W HAMILTON KS STUCKY M 2-17 091651111 COLORADO INTERSTATE GAS CO
029 028S 034W HASKELL KS STUCKY MOR 2-29 091470111 COLORADO INTERSTATE GAS CO
021 024S 038W KEARNY KS SWANK A-1 091850111 COLORADO INTERSTATE GAS CO
021 024S 038W KEARNY KS SWANK 1 091830111 COLORADO INTERSTATE GAS CO
004 027S 036W GRANT KS TATE A-1 092210111 COLORADO INTERSTATE GAS CO
034 026S 036W KEARNY KS TATE B-1 092240111 COLORADO INTERSTATE GAS CO
003 027S 036W GRANT KS TATE C-1 092270111 COLORADO INTERSTATE GAS CO
018 025S 034W FINNEY KS TATE E-1 092272111 COLORADO INTERSTATE GAS CO
018 025S 034W FINNEY KS TATE 1 092120111 COLORADO INTERSTATE GAS CO
032 024S 037W KEARNY KS TATE 1 092140111 COLORADO INTERSTATE GAS CO
032 024S 037W KEARNY KS TATE 1 092090111 COLORADO INTERSTATE GAS CO
036 025S 037W KEARNY KS TATE 2 092150111 COLORADO INTERSTATE GAS CO
004 027S 036W GRANT KS TATE 2-A 092151111 COLORADO INTERSTATE GAS CO
034 026S 036W KEARNY KS TATE 2-B 092152111 COLORADO INTERSTATE GAS CO
003 027S 036W GRANT KS TATE 2-C 092153111 COLORADO INTERSTATE GAS CO
002 026S 037W KEARNY KS TATE 3 092180111 COLORADO INTERSTATE GAS CO
002 026S 037W KEARNY KS TATE 4 092181111 COLORADO INTERSTATE GAS CO
004 027S 036W GRANT KS TATE A-3 092155111 COLORADO INTERSTATE GAS CO
003 027S 036W GRANT KS TATE C-3 092154111 COLORADO INTERSTATE GAS CO
021 023S 037W KEARNY KS TATE CDP 092300000 COLORADO INTERSTATE GAS CO
021 023S 037W KEARNY KS TATE V B 1 092300111 OSBORN HEIRS COMPANY
021 023S 037W KEARNY KS TATE V B (C/G) 1-A 092301111 COLORADO INTERSTATE GAS CO
032 024S 037W KEARNY KS TATE 1-2-32 092159111 COLORADO INTERSTATE GAS CO
036 025S 037W KEARNY KS TATE 2-2-36 092160111 COLORADO INTERSTATE GAS CO
036 025S 034W FINNEY KS TAYLOR A-1 092361111 COLORADO INTERSTATE GAS CO
036 025S 034W FINNEY KS TAYLOR 1 092360111 COLORADO INTERSTATE GAS CO
006 026S 033W FINNEY KS THOMAS 1-2 092439111 KN ENERGY INC
006 026S 033W FINNEY KS THOMAS 1-I 092445111 KN ENERGY INC
024 025S 039W HAMILTON KS THORNBROUGH U S A 1 093140111 COLORADO INTERSTATE GAS CO
024 025S 039W HAMILTON KS THORNBROUGH USA 2 093141111 COLORADO INTERSTATE GAS CO
027 027S 040W STANTON KS TIMM R 1 093200111 COLORADO INTERSTATE GAS CO
027 027S 040W STANTON KS TIMM 2-27 093205111 COLORADO INTERSTATE GAS CO
035 025S 034W FINNEY KS TULLET A-1 093291111 COLORADO INTERSTATE GAS CO
035 025S 034W FINNEY KS TULLETT 1 093290111 COLORADO INTERSTATE GAS CO
017 027S 034W HASKELL KS TUNIS A-1 093320111 COLORADO INTERSTATE GAS CO
017 027S 034W HASKELL KS TUNIS A-2 093321111 COLORADO INTERSTATE GAS CO
018 027S 034W HASKELL KS TUNIS A-3 093322111 COLORADO INTERSTATE GAS CO
010 025S 034W FINNEY KS U S A 1 094220111 COLORADO INTERSTATE GAS CO
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLORADO INTERSTATE GAS COMPANY
MASTER LIST OF GATHERING RECEIPT POINTS
AS OF 09/10/93
HUGOTON/PANOMA AREA G 2 LAM
COUNTY LOCATION
SECTION TOWNSHIP RANGE NAME STATE WELL NAME NUMBER MEASURING PARTY
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
017 025S 037W KEARNY KS UNREIN 1 094060111 COLORADO INTERSTATE GAS CO
017 025S 037W KEARNY KS UNREIN 1-2-17 094061111 COLORADO INTERSTATE GAS CO
017 025S 037W KEARNY KS UNREIN 2-17 094062111 COLORADO INTERSTATE GAS CO
007 029S 033W HASKELL KS UNRUH B-1 094140111 COLORADO INTERSTATE GAS CO
018 026S 039W HAMILTON KS UNRUH 1 094100111 COLORADO INTERSTATE GAS CO
013 021S 035W KEARNY KS UNRUH 1 094101111 COLORADO INTERSTATE GAS CO
007 029S 033W HASKELL KS UNRUH B-3 094142111 COLORADO INTERSTATE GAS CO
018 026S 034W FINNEY KS USA D-7 094344111 COLORADO INTERSTATE GAS CO
010 025S 034W FINNEY KS USA J-1 094346111 COLORADO INTERSTATE GAS CO
006 025S 034W FINNEY KS USA 1-2 094350111 COLORADO INTERSTATE GAS CO
031 030S 031W HASKELL KS VAN BLARICUM A-1 094550111 COLORADO INTERSTATE GAS CO
006 024S 036W KEARNY KS VAN DOREN 1 094650111 COLORADO INTERSTATE GAS CO
006 024S 036W KEARNY KS VAN DOREN C. UNIT 3 094660111 COLORADO INTERSTATE GAS CO
006 024S 036W KEARNY KS VAN DOREN, CATHERINE 2 094655111 COLORADO INTERSTATE GAS CO
016 026S 031W FINNEY KS VANDERREE 1 094600111 COLORADO INTERSTATE GAS CO
015 021S 034W FINNEY KS VAUGHN 1 094710111 COLORADO INTERSTATE GAS CO
002 024S 038W KEARNY KS VICKERS 1 094750111 COLORADO INTERSTATE GAS CO
002 024S 038W KEARNY KS VICKERS 1-A 094751111 COLORADO INTERSTATE GAS CO
001 024S 038W KEARNY KS VICKERS 2 094800111 COLORADO INTERSTATE GAS CO
001 024S 038W KEARNY KS VICKERS 2-A 094801111 COLORADO INTERSTATE GAS CO
036 022S 037W KEARNY KS VIRGINIA 1-A 094815111 COLORADO INTERSTATE GAS CO
003 026S 037W KEARNY KS WAECHTER A-1 095365111 COLORADO INTERSTATE GAS CO
003 026S 037W KEARNY KS WAECHTER 1 095110111 COLORADO INTERSTATE GAS CO
007 025S 034W FINNEY KS WAGNER A-2 095150111 COLORADO INTERSTATE GAS CO
008 025S 034W FINNEY KS WAGNER A-3 095151111 COLORADO INTERSTATE GAS CO
005 025S 034W FINNEY KS WAGNER A-4 095152111 COLORADO INTERSTATE GAS CO
005 025S 034W FINNEY KS WAGNER 5 095160111 COLORADO INTERSTATE GAS CO
007 025S 034W FINNEY KS WAGNER 7 095210111 COLORADO INTERSTATE GAS CO
008 025S 034W FINNEY KS WAGNER 8 095260111 COLORADO INTERSTATE GAS CO
005 025S 034W FINNEY KS WAGNER 5-2 095170111 COLORADO INTERSTATE GAS CO
007 025S 034W FINNEY KS WAGNER 7-2 095165111 COLORADO INTERSTATE GAS CO
008 025S 034W FINNEY KS WAGNER 8-2 095175111 COLORADO INTERSTATE GAS CO
024 027S 034W HASKELL KS WARD 1 095460111 COLORADO INTERSTATE GAS CO
024 027S 034W HASKELL KS WARD A-2 095461111 COLORADO INTERSTATE GAS CO
026 028S 033W HASKELL KS WATKINS A-1 096070111 COLORADO INTERSTATE GAS CO
005 029S 033W HASKELL KS WATKINS 1 096110111 COLORADO INTERSTATE GAS CO
024 030S 032W HASKELL KS WATSON E-1 096160111 COLORADO INTERSTATE GAS CO
011 030S 032W HASKELL KS WATSON 1 065545111 NORTHERN NATURAL GAS PROD
010 030S 032W HASKELL KS WEEKS A-1 096410111 COLORADO INTERSTATE GAS CO
024 028S 032W HASKELL KS WEIDNER 1 096460111 COLORADO INTERSTATE GAS CO
005 027S 031W HASKELL KS WETIG 1 096660111 COLORADO INTERSTATE GAS CO
006 029S 033W HASKELL KS WHEATLEY 1 096810111 COLORADO INTERSTATE GAS CO
012 026S 035W KEARNY KS WHITE A-1 097209111 COLORADO INTERSTATE GAS CO
009 026S 035W KEARNY KS WHITE A-2 097220111 COLORADO INTERSTATE GAS CO
013 026S 035W KEARNY KS WHITE A-3 097221111 COLORADO INTERSTATE GAS CO
001 024S 036W KEARNY KS WHITE 1 097010111 COLORADO INTERSTATE GAS CO
009 026S 035W KEARNY KS WHITE 1 097060111 COLORADO INTERSTATE GAS CO
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLORADO INTERSTATE GAS COMPANY
MASTER LIST OF GATHERING RECEIPT POINTS
AS OF 09/10/93
HUGOTON/PANOMA AREA G 2 LAM
COUNTY LOCATION
SECTION TOWNSHIP RANGE NAME STATE WELL NAME NUMBER MEASURING PARTY
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
012 026S 035W KEARNY KS WHITE 2 097110111 COLORADO INTERSTATE GAS CO
013 026S 035W KEARNY KS WHITE 3 097160111 COLORADO INTERSTATE GAS CO
001 024S 036W KEARNY KS WHITE, ORLIE GAS U 2 097240111 COLORADO INTERSTATE GAS CO
012 031S 032W SEWARD KS WHITNEY 1 097245111 COLORADO INTERSTATE GAS CO
015 024S 038W KEARNY KS WIATT 1 097260111 COLORADO INTERSTATE GAS CO
015 024S 038W KEARNY KS WIATT 1-A 097280111 COLORADO INTERSTATE GAS CO
009 024S 038W KEARNY KS WIATT IMAN 1 097310111 COLORADO INTERSTATE GAS CO
005 026S 034W FINNEY KS WILLIAM MOODY 3-5 071362111 COLORADO INTERSTATE GAS CO
034 022S 037W KEARNY KS WILLIAMS ROYCE 1 097740111 COLORADO INTERSTATE GAS CO
034 022S 037W KEARNY KS WILLIAMS ROYCE 1-A 097741111 COLORADO INTERSTATE GAS CO
029 027S 040W STANTON KS WILLIAMSON M C 1 097810111 COLORADO INTERSTATE GAS CO
029 027S 040W STANTON KS WILLIAMSON 2-29 097811111 COLORADO INTERSTATE GAS CO
025 023S 038W KEARNY KS WILSON 1 097910111 COLORADO INTERSTATE GAS CO
025 023S 038W KEARNY KS WILSON 1-A 097911111 COLORADO INTERSTATE GAS CO
022 027S 040W STANTON KS WILSON 1-22 097912111 COLORADO INTERSTATE GAS CO
027 027S 040W STANTON KS WINGER 7-27 098262111 COLORADO INTERSTATE GAS CO
021 027S 040W STANTON KS WINGER 8-21 098263111 COLORADO INTERSTATE GAS CO
028 027S 040W STANTON KS WINGER 9-28 098264111 COLORADO INTERSTATE GAS CO
033 027S 040W STANTON KS WINGER 10-33 098265111 COLORADO INTERSTATE GAS CO
004 028S 040W STANTON KS WINGER 11-4 098266111 COLORADO INTERSTATE GAS CO
033 027S 040W STANTON KS WINGER C 1 098060111 COLORADO INTERSTATE GAS CO
028 027S 040W STANTON KS WINGER C 2 098110111 COLORADO INTERSTATE GAS CO
004 028S 040W STANTON KS WINGER C 3 098160111 COLORADO INTERSTATE GAS CO
021 027S 040W STANTON KS WINGER C 4 098210111 COLORADO INTERSTATE GAS CO
035 027S 040W STANTON KS WINGER C 5 098260111 COLORADO INTERSTATE GAS CO
035 027S 040W STANTON KS WINGER C 6-35 098261111 COLORADO INTERSTATE GAS CO
023 027S 040W STANTON KS WINGER T R 1 098310111 COLORADO INTERSTATE GAS CO
023 027S 040W STANTON KS WINGER T R 2-23 098311111 COLORADO INTERSTATE GAS CO
023 027S 040W STANTON KS WINGER T. 3-23 098312111 COLORADO INTERSTATE GAS CO
033 027S 040W STANTON KS WINGER 12-33 098267111 COLORADO INTERSTATE GAS CO
028 027S 040W STANTON KS WINGER 13-28 098268111 COLORAOD INTERSTATE GAS CO
004 028S 040W STANTON KS WINGER 14-4 098269111 COLORADO INTERSTATE GAS CO
021 027S 040W STANTON KS WINGER 15-21 098270111 COLORADO INTERSTATE GAS CO
035 027S 040W STANTON KS WINGER 16-35 098271111 COLORDAO INTERSTATE GAS CO
029 028S 034W HASKELL KS WINSTED 1 098410111 COLORADO INTERSTATE GAS CO
029 028S 034W HASKELL KS WINSTED 2-29 098413111 COLORADO INTERSTATE GAS CO
029 028S 034W HASKELL KS WINSTED 4-29 098415111 COLORADO INTERSTATE GAS CO
017 026S 034W FINNEY KS YEISER A-1 099711111 COLORADO INTERSTATE GAS CO
017 026S 034W FINNEY KS YEISER 1 099710111 COLORADO INTERSTATE GAS CO
036 025S 039W HAMILTON KS YINGLING E 1 099850111 COLORADO INTERSTATE GAS CO
036 025S 039W HAMILTON KS YINGLING 2-36 099853111 COLORADO INTERSTATE GAS CO
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLORADO INTERSTATE GAS COMPANY
MASTER LIST OF GATHERING RECEIPT POINTS
AS OF 09/10/93
HUGOTON/PANOMA AREA G 2 LAM
COUNTY LOCATION
SECTION TOWNSHIP RANGE NAME STATE WELL NAME NUMBER MEASURING PARTY
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
011 027S 034W HASKELL KS ADAMS F-1 000510111 COLORADO INTERSTATE GAS CO
027 022S 033W FINNEY KS ADAMS 1 000260111 COLORADO INTERSTATE GAS CO
005 026S 039W HAMILTON KS AKERS BARNEY 1 001630111 COLORADO INTERSTATE GAS CO
018 026S 039W HAMILTON KS AKERS BARNEY 1-18 001635111 COLORADO INTERSTATE GAS CO
005 026S 039W HAMILTON KS AKERS BARNEY 2-5 001631111 COLORADO INTERSTATE GAS CO
033 027S 034W HASKELL KS ALEXANDER A-1 001960111 COLORADO INTERSTATE GAS CO
033 027S 034W HASKELL KS AKEXANDER A-2 001961111 COLORADO INTERSTATE GAS CO
034 027S 034W HASKELL KS ALEXANDER B-1 002010111 COLORADO INTERSTATE GAS CO
034 027S 034W HASKELL KS ALEXANDER B-2 002011111 COLORADO INTERSTATE GAS CO
027 027S 034W HASKELL KS ALEXANDER C-1 002060111 COLORADO INTERSTATE GAS CO
027 027S 034W HASKELL KS ALEXANDER C-2 002061111 COLORADO INTERSTATE GAS CO
028 027S 034W HASKELL KS ALEXANDER F-1 002110111 COLORADO INTERSTATE GAS CO
028 027S 034W HASKELL KS ALEXANDER F-2 002111111 COLORADO INTERSTATE GAS CO
027 027S 034W HASKELL KS ALEXANDER 1 001965111 COLORADO INTERSTATE GAS CO
033 027S 034W HASKELL KS ALEXANDER "O" 1-33 002120111 COLORADO INTERSTATE GAS CO
033 027S 034W HASKELL KS ALEXANDER A-3 001962111 COLORADO INTERSTATE GAS CO
027 027S 034W HASKELL KS ALEXANDER C-3 002062111 COLORADO INTERSTATE GAS CO
028 027S 034W HASKELL KS ALEXANDER F-3 002112111 COLORADO INTERSTATE GAS CO
005 026S 031W FINNEY KS ANGEL 1 002353111 COLORADO INTERSTATE GAS CO
001 028S 033W HASKELL KS ANSHUTZ UNIT 1 002410111 COLORADO INTERSTATE GAS CO
023 025S 037W KEARNY KS APPLEGATE 1 002460111 COLORADO INTERSTATE GAS CO
023 025S 037W KEARNY KS APPLEGATE 1-A 002461111 COLORADO INTERSTATE GAS CO
036 027S 035W GRANT KS APPLEMAN-JACKSON FEE 2 002463111 COLORADO INTERSTATE GAS CO
005 029S 040W STANTON KS ARNOLD 1 002548111 COLORADO INTERSTATE GAS CO
002 025S 036W KEARNY KS BAGNTGE 1 003070111 COLORADO INTERSTATE GAS CO
002 025S 036W KEARNY KS BAHNTGE GAS UNIT 2 003080111 COLORADO INTERSTATE GAS CO
002 025S 036W KEARNY KS BAHNTGE 3-2 003085111 COLORADO INTERSTATE GAS CO
009 024S 038W KEARNY KS BAKKE WIATT A-1 003340111 COLORADO INTERSTATE GAS CO
022 028S 033W HASKELL KS BARBEE 1 003420111 COLORADO INTERSTATE GAS CO
022 028S 033W HASKELL KS BARBEE A-2 003430111 COLORADO INTERSTATE GAS CO
022 028S 033W HASKELL KS BARBEE NO. 1 065543111 NORTHERN NATURAL GAS PROD
012 026S 034W FINNEY KS BARKER 1 006670111 COLORADO INTERSTATE GAS CO
012 026S 034W FINNEY KS BARKER 2 006671111 COLORADO INTERSTATE GAS CO
035 027S 034W HASKELL KS BAUGHMAN C-1 007070111 COLORADO INTERSTATE GAS CO
016 027S 040W STANTON KS BAUGHMAN 2 006970111 COLORADO INTERSTATE GAS CO
016 027S 040W STANTON KS BAUGHMAN 3-16 006980111 COLORADO INTERSTATE GAS CO
005 028S 040W STANTON KS BAUGHMAN 6-16 006990111 COLORADO INTERSTATE GAS CO
032 025S 031W FINNEY KS BEACH 1 007320111 COLORADO INTERSTATE GAS CO
033 025S 031W FINNEY KS BEACH 2-33 007370111 COLORADO INTERSTATE GAS CO
020 025S 031W FINNEY KS BEACH 3 007420111 COLORADO INTERSTATE GAS CO
029 025S 031W FINNEY KS BEACH 4 007470111 COLORADO INTERSTATE GAS CO
028 025S 031W FINNEY KS BEACH 5 007520111 COLORADO INTERSTATE GAS CO
021 025S 031W FINNEY KS BEACH 6 007570111 COLORADO INTERSTATE GAS CO
034 024S 036W KEARNY KS BEATY A-2 007671111 COLORADO INTERSTATE GAS CO
034 024S 036W KEARNY KS BEATY 1 007670111 COLORADO INTERSTATE GAS CO
035 023S 035W KEARNY KS BECKETT 1 007720111 COLORADO INTERSTATE GAS CO
035 023S 035W KEARNY KS BECKETT A-2 007721111 COLORADO INTERSTATE GAS CO
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLORADO INTERSTATE GAS COMPANY
MASTER LIST OF GATHERING RECEIPT POINTS
AS OF 09/10/93
HUGOTON/PANOMA AREA G 2 LAM
COUNTY LOCATION
SECTION TOWNSHIP RANGE NAME STATE WELL NAME NUMBER MEASURING PARTY
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
009 026S 034W FINNEY KS BEDFORD A-1 007771111 COLORADO INTERSTATE GAS CO
008 026S 034W FINNEY KS BEDFORD A-2 007772111 COLORADO INTERSTATE GAS CO
009 026S 034W FINNEY KS BEDFORD 1 007770111 COLORADO INTERSTATE GAS CO
008 026S 034W FINNEY KS BEDFORD 2 007820111 COLORADO INTERSTATE GAS CO
009 023S 037W KEARNY KS BELL B-1 007870111 COLORADO INTERSTATE GAS CO
009 023S 037W KEARNY KS BELL G-1 007930111 COLORADO INTERSTATE GAS CO
029 030S 031W HASKELL KS BEVERLIN SCHMIDT 1 008720111 COLORADO INTERSTATE GAS CO
035 024S 036W KEARNY KS BEYMER A-2 008771111 COLORADO INTERSTATE GAS CO
027 022S 037W KEARNY KS BEYMER 1 008769111 COLORADO INTERSTATE GAS CO
035 024S 036W KEARNY KS BEYMER 1 008770111 COLORADO INTERSTATE GAS CO
027 022S 037W KEARNY KS BEYMER 1-A 008772111 COLORADO INTERSTATE GAS CO
035 024S 036W KEARNY KS BEYMER A-3 008773111 COLORADO INTERSTATE GAS CO
005 029S 040W STANTON KS BIG BOW 991788000 COLORADO INTERSTATE GAS CO
036 030S 032W HASKELL KS BIRD A-1 008820111 COLORADO INTERSTATE GAS CO
002 031S 032W SEWARD KS BIRD B-1 008870111 COLORADO INTERSTATE GAS CO
018 029S 036W GRANT KS BITTIKER KELLER 1 008970111 COLORADO INTERSTATE GAS CO
018 029S 036W GRANT KS BITTIKER KELLER 2 008980111 COLORADO INTERSTATE GAS CO
018 029S 036W GRANT KS BITTIKER-KELLER UNIT 3 008985111 COLORADO INTERSTATE GAS CO
019 027S 031W HASKELL KS BLACK 1 013000111 COLORADO INTERSTATE GAS CO
010 023S 037W KEARNY KS BLESS 1 013090111 COLORADO INTERSTATE GAS CO
036 027S 034W HASKELL KS BRANSTETTER A-1 020320111 COLORADO INTERSTATE GAS CO
036 027S 034W HASKELL KS BRANSTETTER A-3 020322111 COLORADO INTERSTATE GAS CO
023 027S 034W HASKELL KS BRINKMAN 1 020370111 COLORADO INTERSTATE GAS CO
003 026S 039W HAMILTON KS BROTHERS 3-3 020600111 COLORADO INTERSTATE GAS CO
009 026S 039W HAMILTON KS BROTHERS I S 1 020620111 COLORADO INTERSTATE GAS CO
003 026S 039W HAMILTON KS BROTHERS I S 2 020670111 COLORADO INTERSTATE GAS CO
003 026S 039W HAMILTON KS BROTHERS I S 2A 020690111 COLORADO INTERSTATE GAS CO
009 026S 039W HAMILTON KS BROTHERS I S 4-9 020700111 COLORADO INTERSTATE GAS CO
003 026S 039W HAMILTON KS BROTHERS 4-3 020705111 COLORADO INTERSTATE GAS CO
009 026S 039W HAMILTON KS BROTHERS 5-9 020710111 COLORADO INTERSTATE GAS CO
034 025S 034W FINNEY KS BROWN C-1 020773111 COLORADO INTERSTATE GAS CO
002 029S 032W HASKELL KS BROWN 1 020720111 COLORADO INTERSTATE GAS CO
034 025S 034W FINNEY KS BROWN 1 020770111 COLORADO INTERSTATE GAS CO
035 029S 032W HASKELL KS BURGMIER 1 021320111 COLORADO INTERSTATE GAS CO
017 024S 038W KEARNY KS BURNETT 1 021470111 COLORADO INTERSTATE GAS CO
017 024S 038W KEARNY KS BURNETT 1-A 021471111 COLORADO INTERSTATE GAS CO
013 023S 037W KEARNY KS BURNETT WIATT 1 021570111 COLORADO INTERSTATE GAS CO
013 023S 037W KEARNY KS BURNETT WIATT 1-A 021571111 COLORADO INTERSTATE GAS CO
006 029S 034W HASKELL KS BURTON A-2 021780111 COLORADO INTERSTATE GAS CO
006 029S 034W HASKELL KS BURTON 1 021770111 COLORADO INTERSTATE GAS CO
016 028S 040W STANTON KS BUSHART 1 021787111 COLORADO INTERSTATE GAS CO
024 024S 039W HAMILTON KS BUTCHER A-1 021790111 ANADARKO PETROLEUM CORP.
014 025S 036W KEARNY KS CAMPBELL A-1 023989111 COLORADO INTERSTATE GAS CO
018 025S 035W KEARNY KS CAMPBELL A-2 023994111 COLORADO INTERSTATE GAS CO
015 023S 035W KEARNY KS CAMPBELL B-1 023990111 COLORADO INTERSTATE GAS CO
018 025S 035W KEARNY KS CAMPBELL 1 023840111 COLORADO INTERSTATE GAS CO
005 024S 036W KEARNY KS CAMPBELL 1 023790111 COLORADO INTERSTATE GAS CO
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLORADO INTERSTATE GAS COMPANY
MASTER LIST OF GATHERING RECEIPT POINTS
AS OF 09/10/93
HUGOTON/PANOMA AREA G 2 LAM
COUNTY LOCATION
SECTION TOWNSHIP RANGE NAME STATE WELL NAME NUMBER MEASURING PARTY
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
014 025S 036W KEARNY KS CAMPBELL 2 023940111 COLORADO INTERSTATE GAS CO
005 024S 036W KEARNY KS CAMPBELL GAS UNIT 2 024000111 COLORADO INTERSTATE GAS CO
005 024S 036W KEARNY KS CAMPBELL GAS UNIT 3 024005111 COLORADO INTERSTATE GAS CO
017 025S 035W KEARNY KS CAMPBELL 1-2 023841111 COLORADO INTERSTATE GAS CO
014 025S 036W KEARNY KS CAMPBELL 2-2 023941111 COLORADO INTERSTATE GAS CO
023 023S 035W KEARNY KS CANNON 1 024090111 COLORADO INTERSTATE GAS CO
006 026S 034W FINNEY KS CARLTON B-1 024891111 COLORADO INTERSTATE GAS CO
006 026S 034W FINNEY KS CARLTON 1 024890111 COLORADO INTERSTATE GAS CO
017 027S 040W STANTON KS CARRITHERS 1 024893111 COLORADO INTERSTATE GAS CO
017 027S 040W STANTON KS CARRITHERS #2 024894111 COLORADO INTERSTATE GAS CO
011 026S 035W KEARNY KS CB&L B-1 025442111 COLORADO INTERSTATE GAS CO
025 026S 035W KEARNY KS CB&L B-2 025443111 COLORADO INTERSTATE GAS CO
014 026S 035W KEARNY KS CB&L B-3 025444111 COLORADO INTERSTATE GAS CO
010 026S 035W KEARNY KS CB&L B-4 025445111 COLORADO INTERSTATE GAS CO
023 026S 035W KEARNY KS CB&L B-5 025446111 COLORADO INTERSTATE GAS CO
024 026S 035W KEARNY KS CB&L B-6 025447111 COLORADO INTERSTATE GAS CO
035 026S 035W KEARNY KS CB&L B-7 025448111 COLORADO INTERSTATE GAS CO
022 026S 035W KEARNY KS CB&L B-8 025449111 COLORADO INTERSTATE GAS CO
034 026S 035W KEARNY KS CB&L B-9 025450111 COLORADO INTERSTATE GAS CO
026 026S 035W KEARNY KS CB&L B-10 025451111 COLORADO INTERSTATE GAS CO
015 026S 035W KEARNY KS CB&L C-1 025970111 COLORADO INTERSTATE GAS CO
018 021S 034W FINNEY KS CHRISTABELLE 1 025300111 COLORADO INTERSTATE GAS CO
014 026S 035W KEARNY KS CITIZNES BLDG X LN 1 025440111 COLORADO INTERSTATE GAS CO
024 026S 035W KEARNY KS CITIZENS BLDG X LN 2 025490111 COLORADO INTERSTATE GAS CO
023 026S 035W KEARNY KS CITIZENS BLDG X LN 3 025540111 COLORADO INTERSTATE GAS CO
025 026S 035W KEARNY KS CITIZENS BLD X LN 4 025590111 COLORADO INTERSTATE GAS CO
027 026S 035W KEARNY KS CITIZENS BLDG X LN 5 025640111 COLORADO INTERSTATE GAS CO
034 026S 035W KEARNY KS CITIZENS BLDG X LN 6 025690111 COLORADO INTERSTATE GAS CO
035 026S 035W KEARNY KS CITIZENS BLDG X LN 7 025740111 COLORADO INTERSTATE GAS CO
022 026S 035W KEARNY KS CITIZENS BLDG X LN 8 025790111 COLORADO INTERSTATE GAS CO
010 026S 035W KEARNY KS CITIZENS BLDG X LN 9 025840111 COLORADO INTERSTATE GAS CO
011 026S 035W KEARNY KS CITIZENS BLDG X LN 10 025890111 COLORADO INTERSTATE GAS CO
015 026S 035W KEARNY KS CITIZENS BLDG X LN 11 025940111 COLORADO INTERSTATE GAS CO
016 028S 040W STANTON KS CLARK H J 1 026090111 COLORADO INTERSTATE GAS CO
004 029S 040W STANTON KS CLARK VIRGIL F 1 094810111 COLORADO INTERSTATE GAS CO
013 028S 041W STANTON KS COCKREHAM 1 026320111 COLORADO INTERSTATE GAS CO
007 028S 040W STANTON KS COCKREHAM/LANE/BEARMAN CD 991791000 COLORADO INTERSTATE GAS CO
036 028S 035W GRANT KS COKE 1 026440111 COLORADO INTERSTATE GAS CO
036 028S 035W GRANT KS COKE 1-A 026442111 COLORADO INTERSTATE GAS CO
019 031S 031W SEWARD KS COLLEGE, S.W. 1 026585111 COLORADO INTERSTATE GAS CO
013 024S 038W KEARNY KS COLLINGWOOD 1 026640111 COLORADO INTERSTATE GAS CO
013 024S 038W KEARNY KS COLLINGWOOD 1-A 026620111 COLORADO INTERSTATE GAS CO
022 027S 040W STANTON KS COLLINGWOOD A J 1 026790111 COLORADO INTERSTATE GAS CO
022 027S 040W STANTON KS COLLINGWOOD 9-22 026718111 COLORADO INTERSTATE GAS CO
017 028S 033W HASKELL KS CONVERSE #1 026792111 COLORADO INTERSTATE GAS CO
017 028S 033W HASKELL KS CONVERSE #1-2 026793111 COLORADO INTERSTATE GAS CO
026 027S 034W HASKELL KS COOK C-1 026990111 COLORADO INTERSTATE GAS CO
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLORADO INTERSTATE GAS COMPANY
MASTER LIST OF GATHERING RECEIPT POINTS
AS OF 09/10/93
HUGOTON/PANOMA AREA G 2 LAM
COUNTY LOCATION
SECTION TOWNSHIP RANGE NAME STATE WELL NAME NUMBER MEASURING PARTY
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
008 028S 040W STANTON KS COOPER E D 1 027090111 COLORADO INTERSTATE GAS CO
022 023S 035W KEARNY KS CORSE 1 027290111 COLORADO INTERSTATE GAS CO
007 024S 034W FINNEY KS CRAWFORD GAS UNIT A-3 065909111 WILLIAMS NATURAL GAS COMP
006 028S 040W STANTON KS CROSS 1 028385111 COLORADO INTERSTATE GAS CO
032 027S 040W STANTON KS CROSS J L 2 028390111 COLORADO INTERSTATE GAS CO
036 027S 041S STANTON KS CROSS LR & CE 1 028400111 COLORADO INTERSTATE GAS CO
032 027S 040W STANTON KS CROSS 3-32 028395111 COLORADO INTERSTATE GAS CO
031 027S 040W STANTON KS CROSS, LEROY UNIT-1 1 040050111 COLORADO INTERSTATE GAS CO
031 026S 034W FINNEY KS CURRY A-1 028541111 COLORADO INTERSTATE GAS CO
027 026S 034W FINNEY KS CURRY B-1 028542111 COLORADO INTERSTATE GAS CO
006 027S 034W HASKELL KS CURRY C-1 028543111 COLORADO INTERSTATE GAS CO
031 026S 034W FINNEY KS CURRY 1 028440111 COLORADO INTERSTATE GAS CO
006 027S 034W HASKELL KS CURRY 2 028490111 COLORADO INTERSTATE GAS CO
034 026S 034W FINNEY KS CURRY 3 028540111 COLORADO INTERSTATE GAS CO
006 027S 034W HASKELL KS CURRY 2-2 028491111 COLORADO INTERSTATE GAS CO
021 023S 036S KEARNY KS D. RATZLAFF "B" NO 3 078437111 COLORADO INTERSTATE GAS CO
020 027S 034W HASKELL KS DA VATZ D-1 028850111 COLORADO INTERSTATE GAS CO
021 022S 033W FINNEY KS DAMME 2 028650111 COLORADO INTERSTATE GAS CO
028 022S 033W FINNEY KS DAMME 7 028700111 COLORADO INTERSTATE GAS CO
033 022S 033W FINNEY KS DAMME 8 028750111 COLORADO INTERSTATE GAS CO
030 023S 034W FINNEY KS DANLER 1 028800111 COLORADO INTERSTATE GAS CO
030 023S 034W FINNEY KS DANLER 2 028801111 COLORADO INTERSTATE GAS CO
030 023S 034W FINNEY KS DANLER #3 028802111 COLORADO INTERSTATE GAS CO
020 027S 034W HASKELL KS DAVATZ D-2 028851111 COLORADO INTERSTATE GAS CO
020 027S 034W HASKELL KS DAVATZ D-3 028852111 COLORADO INTERSTATE GAS CO
007 027S 031W HASKELL KS DAVIS B-1 029100111 COLORADO INTERSTATE GAS CO
035 022S 037W KEARNY KS DAVIS 1 028999111 COLORADO INTERSTATE GAS CO
002 023S 037W KEARNY KS DAVIS 1 029000111 COLORADO INTERSTATE GAS CO
035 022S 037W KEARNY KS DAVIS 2-A 029055111 COLORADO INTERSTATE GAS CO
001 029S 034W HASKELL KS DENNIS B-1 029450111 COLORADO INTERSTATE GAS CO
026 029S 033W HASKELL KS DENNIS MOR B-1 029460111 COLORADO INTERSTATE GAS CO
019 026S 034W FINNEY KS DEVLIN 1 029800111 COLORADO INTERSTATE GAS CO
019 026S 034W FINNEY KS DEVLIN 2 029989111 COLORADO INTERSTATE GAS CO
019 026S 034W FINNEY KS DEVLIN A 1-H 029991111 COLORADO INTERSTATE GAS CO
017 029S 033W HASKELL KS DEWELL 1 029850111 COLORADO INTERSTATE GAS CO
017 029S 033W HASKELL KS DEWELL A-2 029996111 COLORADO INTERSTATE GAS CO
012 028S 041W STANTON KS DIMITT 1 029890111 COLORADO INTERSTATE GAS CO
031 029S 036W GRANT KS DOROTHY LIMPER UNIT 2X 056045111 COLORADO INTERSTATE GAS C0
031 029S 036W GRANT KS DOROTHY LIMPER UNIT 3 056050111 COLORADO INTERSTATE GAS CO
029 025S 033W FINNEY KS E. C. MOODY 3-29 071062111 COLORADO INTERSTATE GAS CO
033 024S 037W KEARNY KS E. E. ROBRAHN NO. 3 079636111 COLORADO INTERSTATE GAS CO
015 029S 036W GRANT KS E. GRAY UNIT 3 039545111 COLORADO INTERSTATE GAS CO
029 029S 036W GRANT KS E. KELLER UNIT 3 052535111 COLORADO INTERSTATE GAS CO
003 027S 040W STANTON KS EDIGAR 1-3 031620111 COLORADO INTERSTATE GAS CO
005 028S 034W HASKELL KS ELLIOTT A-4 031730111 COLORADO INTERSTATE GAS CO
005 028S 034W HASKELL KS ELLIOTT 1 031720111 COLORADO INTERSTATE GAS CO
005 028S 034W HASKELL KS ELLIOTT A-5 031731111 COLORADO INTERSTATE GAS CO
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLORADO INTERSTATE GAS COMPANY
MASTER LIST OF GATHERING RECEIPT POINTS
AS OF 09/10/93
HUGOTON/PANOMA AREA G 2 LAM
COUNTY LOCATION
SECTION TOWNSHIP RANGE NAME STATE WELL NAME NUMBER MEASURING PARTY
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
018 031S 031W SEWARD KS ELLIS 31 A-1 031770111 COLORADO INTERSTATE GAS CO
025 022S 037W KEARNY KS ELVA 1-A 031850111 COLORADO INTERSTATE GAS CO
022 027S 034W HASKELL KS ENGLER B-1 031875111 COLORADO INTERSTATE GAS CO
022 025S 039W HAMILTON KS ENGLERT J A 1 031895111 COLORADO INTERSTATE GAS CO
027 025S 039W HAMILTON KS ENGLERT R M 1 031900111 COLORADO INTERSTATE GAS CO
027 025S 039W HAMILTON KS ENGLERT R M 2 031901111 COLORADO INTERSTATE GAS CO
006 024S 034W FINNEY KS ESTHER 1 031970111 COLORADO INTERSTATE GAS CO
006 024S 034W FINNEY KS ESTHER 2 031971111 COLORADO INTERSTATE GAS CO
028 028S 034W HASKELL KS EUBANK A-1 032020111 COLORADO INTERSTATE GAS CO
023 028S 034W HASKELL KS EUBANK B-1 032120111 COLORADO INTERSTATE GAS CO
007 028S 034W HASKELL KS EUBANK C-1 032170111 COLORADO INTERSTATE GAS CO
007 028S 034W HASKELL KS EUBANK C-4 032173111 COLORADO INTERSTATE GAS CO
028 028S 034W HASKELL KS EUBANK A-2 032365111 COLORADO INTERSTATE GAS CO
023 028S 034W HASKELL KS EUBANK B-2 032366111 COLORADO INTERSTATE GAS CO
033 028S 034W HASKELL KS EUBANK M H 1 032270111 COLORADO INTERSTATE GAS CO
033 028S 034W HASKELL KS EUBANK-CSGH A-3 032070111 COLORADO INTERSTATE GAS CO
033 028S 034W HASKELL KS EUBANK-CSGH D-1 032220111 COLORADO INTERSTATE GAS CO
033 028S 034W HASKELL KS EUBANKS A-2 032370111 COLORADO INTERSTATE GAS CO
033 028S 034W HASKELL KS EUBANKS D-3 032420111 COLORADO INTERSTATE GAS CO
033 028S 034W HASKELL KS EUBANKS CSGH D-3 032470111 COLORADO INTERSTATE GAS CO
028 028S 034W HASKELL KS EUBANKS CSHG 2 032320111 COLORADO INTERSTATE GAS CO
033 028S 034W HASKELL KS EUBANKS 2-33 032175111 COLORADO INTERSTATE GAS CO
035 022S 033W FINNEY KS EVERS A-1 033370111 COLORADO INTERSTATE GAS CO
010 026S 039W HAMILTON KS FEDERAL FARM MORTG. 1-10 033758111 COLORADO INTERSTATE GAS CO
036 027S 035W GRANT KS FEE 1 033820111 COLORADO INTERSTATE GAS CO
036 025S 039W HAMILTON KS FIELD 1-36 035100111 COLORADO INTERSTATE GAS CO
030 030S 031W HASKELL KS FINCHAM 1 035170111 COLORADO INTERSTATE GAS CO
026 025S 039W HAMILTON KS FINDLAY GAS UNIT 1 035180111 COLORADO INTERSTATE GAS CO
023 023S 037W KEARNY KS FINKELSTEIN 1 035220111 COLORADO INTERSTATE GAS CO
023 023S 037W KEARNY KS FINKELSTEIN 1-A 035221111 COLORADO INTERSTATE GAS CO
026 025S 039W HAMILTON KS FINLAY GAS UNIT 2 035225111 COLORADO INTERSTATE GAS CO
017 022S 033W FINNEY KS FINNUP B-1 035370111 COLORADO INTERSTATE GAS CO
029 024S 037W KEARNY KS FINNUP 1 035270111 COLORADO INTERSTATE GAS CO
029 024S 037W KEARNY KS FINNUP 1-A 035271111 COLORADO INTERSTATE GAS CO
034 022S 033W FINNEY KS FINNUP 2 035320111 COLORADO INTERSTATE GAS CO
004 028S 034W HASKELL KS FLETCHER G-1 035675111 COLORADO INTERSTATE GAS CO
026 024S 036W KEARNY KS FLETCHER B-1 035570111 COLORADO INTERSTATE GAS CO
026 024S 036W KEARNY KS FLETCHER B-2 035571111 COLORADO INTERSTATE GAS CO
004 028S 034W HASKELL KS FLETCHER 1 035520111 COLORADO INTERSTATE GAS CO
004 028S 034W HASKELL KS FLETCHER A-2 035525111 COLORADO INTERSTATE GAS CO
009 028S 040W STANTON KS FLOYD 2-9 035721111 COLORADO INTERSTATE GAS CO
009 028S 040W STANTON KS FLOYD E 1 035720111 COLORADO INTERSTATE GAS CO
006 028S 040W STANTON KS FLOYD 3-9 035722111 COLORADO INTERSTATE GAS CO
036 028S 032W HASKELL KS FOSTER 1 035970111 COLORADO INTERSTATE GAS CO
030 027S 040W STANTON KS FRASER N E 1 036270111 COLORADO INTERSTATE GAS CO
004 024S 036W KEARNY KS FRAZIER 1 036320111 COLORADO INTERSTATE GAS CO
004 024S 036W KEARNY KS FRAZIER GAS UNIT 2 036375111 COLORADO INTERSTATE GAS CO
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLORADO INTERSTATE GAS COMPANY
MASTER LIST OF GATHERING RECEIPT POINTS
AS OF 09/10/93
HUGOTON/PANOMA AREA G 2 LAM
COUNTY LOCATION
SECTION TOWNSHIP RANGE NAME STATE WELL NAME NUMBER MEASURING PARTY
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
004 024S 036W KEARNY KS FRAZIER GAS UNIT 3 036376111 COLORADO INTERSTATE GAS CO
020 026S 039W HAMILTON KS FREASE 2-20 036421111 COLORADO INTERSTATE GAS CO
020 026S 039W HAMILTON KS FREASE E M 1 036420111 COLORADO INTERSTATE GAS CO
025 025S 039W HAMILTON KS FREASE E M 3-25 036422111 COLORADO INTERSTATE GAS CO
023 025S 039W HAMILTON KS FREASE GAS UNIT 1 036410111 COLORADO INTERSTATE GAS CO
020 026S 039W HAMILTON KS FREASE 4-20 036423111 COLORADO INTERSTATE GAS CO
018 027S 033W HASKELL KS FREY B-1 036520111 COLORADO INTERSTATE GAS CO
018 027S 033W HASKELL KS FREY B-2 036540111 COLORADO INTERSTATE GAS CO
019 027S 033W HASKELL KS FREY C-1 036570111 COLORADO INTERSTATE GAS CO
019 027S 033W HASKELL KS FREY C-2 036590111 COLORADO INTERSTATE GAS CO
013 027S 034W HASKELL KS FREY D-1 036620111 COLORADO INTERSTATE GAS CO
018 027S 033W HASKELL KS FREY B-3 036541111 COLORADO INTERSTATE GAS CO
019 027S 033W HASKELL KS FREY C-3 036595111 COLORADO INTERSTATE GAS CO
013 027S 034W HASKELL KS FREY D-2 036621111 COLORADO INTERSTATE GAS CO
021 029S 036W GRANT KS G. HAGERMAN UNIT 3 041325111 COLORADO INTERSTATE GAS CO
001 027S 032W HASKELL KS GALE 1 037380111 COLORADO INTERSTATE GAS CO
013 023S 035W KEARNY KS GARDEN B-2 037481111 COLORADO INTERSTATE GAS CO
001 024S 035W KEARNY KS GARDEN A-1 037430111 COLORADO INTERSTATE GAS CO
001 024S 035W KEARNY KS GARDEN A-3 037432111 COLORADO INTERSTATE GAS CO
013 023S 035W KEARNY KS GARDEN B-1 037480111 COLORADO INTERSTATE GAS CO
001 024S 035W KEARNY KS GARDEN A-4 037433111 COLORADO INTERSTATE GAS CO
013 023S 035W KEARNY KS GARDEN B D1-13 037475111 COLORADO INTERSTATE GAS CO
031 023S 034W FINNEY KS GARDEN CITY B-3 037633111 COLORADO INTERSTATE GAS CO
033 023S 034W FINNEY KS GARDEN CITY A-1 037580111 COLORADO INTERSTATE GAS CO
031 023S 034W FINNEY KS GARDEN CITY B-1 037630111 COLORADO INTERSTATE GAS CO
029 023S 034W FINNEY KS GARDEN CITY C-1 037680111 COLORADO INTERSTATE GAS CO
028 023S 034W FINNEY KS GARDEN CITY D-1 037730111 COLORADO INTERSTATE GAS CO
032 023S 034W FINNEY KS GARDEN CITY E-1 037780111 COLORADO INTERSTATE GAS CO
027 023S 034W FINNEY KS GARDEN CITY G-1 037830111 COLORADO INTERSTATE GAS CO
025 023S 034W FINNEY KS GARDEN CITY J-1 037880111 COLORADO INTERSTATE GAS CO
026 023S 034W FINNEY KS GARDEN CITY K-1 037930111 COLORADO INTERSTATE GAS CO
034 023S 034W FINNEY KS GARDEN CITY L-1 037980111 COLORADO INTERSTATE GAS CO
036 023S 035W KEARNY KS GARDEN CITY N-1 038030111 COLORADO INTERSTATE GAS CO
013 022S 034W FINNEY KS GARDEN CITY 1 037530111 COLORADO INTERSTATE GAS CO
033 023S 034W FINNEY KS GARDEN CITY A-2 037585111 COLORADO INTERSTATE GAS CO
031 023S 034W FINNEY KS GARDEN CITY B-4 037634111 COLORADO INTERSTATE GAS CO
029 023S 034W FINNEY KS GARDEN CITY C-2 037681111 COLORADO INTERSTATE GAS CO
028 023S 034W FINNEY KS GARDEN CITY D-2 038045111 COLORADO INTERSTATE GAS CO
032 023S 034W FINNEY KS GARDEN CITY E-2 037785111 COLORADO INTERSTATE GAS CO
036 023S 035W KEARNY KS GARDEN CITY P-1 038040111 COLORADO INTERSTATE GAS CO
005 024S 034W FINNEY KS GARNAND 1 038130111 COLORADO INTERSTATE GAS CO
005 024S 034W FINNEY KS GARNAND 2 038131111 COLORADO INTERSTATE GAS CO
005 024S 034W FINNEY KS GARNAND 3-5 038132111 COLORADO INTERSTATE GAS CO
021 027S 034W HASKELL KS GARRISON A-1 038230111 COLORADO INTERSTATE GAS CO
021 027S 034W HASKELL KS GARRISON A-2 038231111 COLORADO INTERSTATE GAS CO
021 027S 034W HASKELL KS GARRISON A-3 038232111 COLORADO INTERSTATE GAS CO
004 023S 033W FINNEY KS GARRY 1 038280111 COLORADO INTERSTATE GAS CO
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLORADO INTERSTATE GAS COMPANY
MASTER LIST OF GATHERING RECEIPT POINTS
AS OF 09/10/93
HUGOTON/PANOMA AREA G 2 LAM
COUNTY LOCATION
SECTION TOWNSHIP RANGE NAME STATE WELL NAME NUMBER MEASURING PARTY
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
026 023S 035W KEARNY KS GILLOCK 1 038580111 COLORADO INTERSTATE GAS CO
017 030S 031W HASKELL KS GLEASON 038830111 COLORADO INTERSTATE GAS CO
003 026S 034W FINNEY KS GOVERNMENT A-1 039290111 COLORADO INTERSTATE GAS CO
010 026S 034W FINNEY KS GOVERNMENT A-2 039291111 COLORADO INTERSTATE GAS CO
012 027S 034W HASKELL KS GOVERNMENT A-3 039292111 COLORADO INTERSTATE GAS CO
003 026S 034W FINNEY KS GOVERNMENT 1 039280111 COLORADO INTERSTATE GAS CO
010 026S 034W FINNEY KS GOVERNMENT 2 039330111 COLORADO INTERSTATE GAS CO
012 027S 034W HASKELL KS GOVERNMENT 3 039380111 COLORADO INTERSTATE GAS CO
026 026S 040W HAMILTON KS GRABER 1 039500111 COLORADO INTERSTATE GAS CO
026 026S 040W HAMILTON KS GRABER 1 037400111 COLORADO INTERSTATE GAS CO
016 029S 036W GRANT KS GRAY ETHEL 2 039540111 COLORADO INTERSTATE GAS CO
022 029S 036W GRANT KS GRAY ETHEL 1 039530111 COLORADO INTERSTATE GAS CO
030 028S 034W HASKELL KS GREEN C-1 039630111 COLORADO INTERSTATE GAS CO
030 028S 034W HASKELL KS GREEN C-2 039631111 COLORADO INTERSTATE GAS CO
012 024S 037W KEARNY KS GREEN 2 039620111 COLORADO INTERSTATE GAS CO
012 024S 037W KEARNY KS GREEN GAS UNIT NO. 3 039621111 COLORADO INTERSTATE GAS CO
013 024S 037W KEARNY KS GREEN R L 1 039580111 COLORADO INTERSTATE GAS CO
013 024S 037W KEARNY KS GREEN R L 2 039581111 COLORADO INTERSTATE GAS CO
012 024S 037W KEARNY KS GREEN UNIT 1 039680111 COLORADO INTERSTATE GAS CO
004 029S 034W HASKELL KS GREGG 1 039930111 COLORADO INTERSTATE GAS CO
032 028S 034W HASKELL KS GREGG 8-32 039932111 COLORADO INTERSTATE GAS CO
032 028S 034W HASKELL KS GREGG 8-32 039933111 COLORADO INTERSTATE GAS CO
018 023S 037W KEARNY KS GROPP 1-A 039981111 COLORADO INTERSTATE GAS CO
018 023S 037W KEARNY KS GROPP UNIT 1 039980111 COLORADO INTERSTATE GAS CO
002 027S 034W HASKELL KS GUNNELL A-1 040231111 COLORADO INTERSTATE GAS CO
002 027S 034W HASKELL KS GUNNELL 1 040230111 COLORADO INTERSTATE GAS CO
011 024S 036W KEARNY KS HAAG 1 040810111 COLORADO INTERSTATE GAS CO
011 024S 036W KEARNY KS HAAG UNIT 2 040865111 COLORADO INTERSTATE GAS CO
011 024S 036W KEARNY KS HAAG UNIT 3 040866111 COLORADO INTERSTATE GAS CO
026 028S 033W HASKELL KS HACKER 1 040910111 COLORADO INTERSTATE GAS CO
021 029S 036W GRANT KS HAGERMAN GEORGE 1 041310111 COLORADO INTERSTATE GAS CO
021 029S 036W GRANT KS HAGERMAN GEORGE 2 041320111 COLORADO INTERSTATE GAS CO
028 029S 036W GRANT KS HAGERMAN SALLIE 1 041360111 COLORADO INTERSTATE GAS CO
028 029S 036W GRANT KS HAGERMAN SALLIE 2 041370111 COLORADO INTERSTATE GAS CO
020 029S 036W GRANT KS HAGERMAN UNIT 1 041410111 COLORADO INTERSTATE GAS CO
020 029S 036W GRANT KS HAGERMAN UNIT 2 041420111 COLORADO INTERSTATE GAS CO
020 029S 036W GRANT KS HAGERMAN UNIT 3 041326111 COLORADO INTERSTATE GAS CO
005 029S 034W HASKELL KS HALL K-1 041760111 COLORADO INTERSTATE GAS CO
005 029S 034W HASKELL KS HALL K-6 041991111 COLORADO INTERSTATE GAS CO
034 028S 032W HASKELL KS HALL 1 041560111 COLORADO INTERSTATE GAS CO
005 029S 034W HASKELL KS HALL (L/K) K-4 041910111 COLORADO INTERSTATE GAS CO
005 029S 034W HASKELL KS HALL (LAN) K-5 041990111 COLORADO INTERSTATE GAS CO
005 029S 034W HASKELL KS HALL (TRN) K-4 041960111 COLORADO INTERSTATE GAS CO
005 029S 034W HASKELL KS HALL CHE K-4 041860111 COLORADO INTERSTATE GAS CO
005 029S 034W HASKELL KS HALL CSHG K-2 041810111 COLORADO INTERSTATE GAS CO
005 029S 034W HASKELL KS HALL K-10 041995111 COLORADO INTERSTATE GAS CO
025 023S 035W KEARNY KS HAMLIN 1 042410111 COLORADO INTERSTATE GAS CO
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLORADO INTERSTATE GAS COMPANY
MASTER LIST OF GATHERING RECEIPT POINTS
AS OF 09/10/93
HUGOTON/PANOMA AREA G 2 LAM
COUNTY LOCATION
SECTION TOWNSHIP RANGE NAME STATE WELL NAME NUMBER MEASURING PARTY
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
025 023S 035W KEARNY KS HAMLIN A-2 042411111 COLORADO INTERSTATE GAS CO
015 026S 034W FINNEY KS HATFIELD 1 043260111 COLORADO INTERSTATE GAS CO
015 026S 034W FINNEY KS HATFIELD GAS UNIT 2 043261111 COLORADO INTERSTATE GAS CO
015 026S 034W FINNEY KS HATFIELD 3-15 043262111 COLORADO INTERSTATE GAS CO
030 026S 039W HAMILTON KS HATTRUP L J 1 043310111 COLORADO INTERSTATE GAS CO
030 026S 039W HAMILTON KS HATTRUP 3-30 043295111 COLORADO INTERSTATE GAS CO
030 026S 039W HAMILTON KS HATTRUPP 2-30 043290111 COLORADO INTERSTATE GAS CO
034 023S 038W KEARNY KS HAWK 1 043460111 COLORADO INTERSTATE GAS CO
034 023S 038W KEARNY KS HAWK 1-A 043461111 COLORADO INTERSTATE GAS CO
028 024S 037W KEARNY KS HEFNER 1 043960111 COLORADO INTERSTATE GAS CO
028 024S 037W KEARNY KS HEFNER 2 043961111 COLORADO INTERSTATE GAS CO
028 024S 037W KEARNY KS HEFNER GAS UNIT NO. 3 043962111 COLORADO INTERSTATE GAS CO
006 025S 037W KEARNY KS HEINTZ 1 044010111 COLORADO INTERSTATE GAS CO
006 025S 037W KEARNY KS HEINTZ GAS UNIT 2 044011111 COLORADO INTERSTATE GAS CO
006 025S 037W KEARNY KS HEINTZ 3-6 044115111 COLORADO INTERSTATE GAS CO
036 026S 040W HAMILTON KS HELTEMES 1-36 044140111 COLORADO INTERSTATE GAS CO
019 026S 039W HAMILTON KS HELTEMES 4-19 044143111 COLORADO INTERSTATE GAS CO
025 026S 040W HAMILTON KS HELTEMES 5-25 044144111 COLORADO INTERSTATE GAS CO
019 026S 039W HAMILTON KS HELTEMES N A 1 044160111 COLORADO INTERSTATE GAS CO
036 026S 040W HAMILTON KS HELTEMES N A 2 044210111 COLORADO INTERSTATE GAS CO
025 026S 040W HAMILTON KS HELTEMES N A 3 044260111 COLORADO INTERSTATE GAS CO
019 026S 039W HAMILTON KS HELTEMES 6-19 044145111 COLORADO INTERSTATE GAS CO
025 026S 040W HAMILTON KS HELTEMES 7-25 044146111 COLORADO INTERSTATE GAS CO
036 026S 040W HAMILTON KS HELTEMES 8-36 044147111 COLORADO INTERSTATE GAS CO
007 028S 040W STANTON KS HERRICK, WALTER 1 044335111 COLORADO INTERSTATE GAS CO
023 029S 032W HASKELL KS HESKAMP 1 044960111 COLORADO INTERSTATE GAS CO
017 030S 035W GRANT KS HICKOK 045210000 COLORADO INTERSTATE GAS CO
017 030S 035W GRANT KS HICKOK 1-A 045215111 COLORADO INTERSTATE GAS CO
020 030S 035W GRANT KS HICKOK 2-A 045220111 COLORADO INTERSTATE GAS CO
020 030S 035W GRANT KS HICKOK #2 DELIVERY 045260000 COLORADO INTERSTATE GAS CO
011 026S 037W KEARNY KS HILLYARD A-1 045930111 COLORADO INTERSTATE GAS CO
010 026S 037W KEARNY KS HILLYARD A-2 045931111 COLORADO INTERSTATE GAS CO
018 026S 036W KEARNY KS HILLYARD A-3 045932111 COLORADO INTERSTATE GAS CO
020 026S 036W KEARNY KS HILLYARD A-4 045933111 COLORADO INTERSTATE GAS CO
014 026S 037W KEARNY KS HILLYARD A-5 045934111 COLORADO INTERSTATE GAS CO
011 026S 037W KEARNY KS HILLYARD 1 045710111 COLORADO INTERSTATE GAS CO
010 026S 037W KEARNY KS HILLYARD 2 045760111 COLORADO INTERSTATE GAS CO
018 026S 036W KEARNY KS HILLYARD 3 045810111 COLORADO INTERSTATE GAS CO
020 026S 036W KEARNY KS HILLYARD 4 045860111 COLORADO INTERSTATE GAS CO
014 026S 037W KEARNY KS HILLYARD 5 045910111 COLORADO INTERSTATE GAS CO
021 026S 036W KEARNY KS HILLYARD 4-2 045861111 COLORADO INTERSTATE GAS CO
006 030S 033W HASKELL KS HOFFMAN B-1 046410111 COLORADO INTERSTATE GAS CO
006 030S 033W HASKELL KS HOFFMAN B-1 046360111 COLORADO INTERSTATE GAS CO
016 026S 039W HAMILTON KS HOFFMAN 2-16 046340111 COLORADO INTERSTATE GAS CO
016 026S 039W HAMILTON KS HOFFMAN C A 1 046460111 COLORADO INTERSTATE GAS CO
016 026S 039W HAMILTON KS HOFFMAN 3-16 046345111 COLORADO INTERSTATE GAS CO
025 022S 033W FINNEY KS HOLSTED-THOMASON 2 042360111 COLORADO INTERSTATE GAS CO
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLORADO INTERSTATE GAS COMPANY
MASTER LIST OF GATHERING RECEIPT POINTS
AS OF 09/10/93
HUGOTON/PANOMA AREA G 2 LAM
COUNTY LOCATION
SECTION TOWNSHIP RANGE NAME STATE WELL NAME NUMBER MEASURING PARTY
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
015 028S 034W HASKELL KS HOME ROYALTY A-2 046661111 COLORADO INTERSTATE GAS CO
015 028S 034W HASKELL KS HOME ROYALTY ASSN 1 046660111 COLORADO INTERSTATE GAS CO
015 031S 032W SEWARD KS HOMSHER PJ-2 046700111 COLORADO INTERSTATE GAS CO
023 024S 038W KEARNY KS HOOVER 1 046760111 COLORADO INTERSTATE GAS CO
023 024S 038W KEARNY KS HOOVER 1-A 046761111 COLORADO INTERSTATE GAS CO
023 024S 038W KEARNY KS HOOVER 2 046762111 COLORADO INTERSTATE GAS CO
014 023S 037W KEARNY KS HOOVER, HELEN 1 046810111 COLORADO INTERSTATE GAS CO
014 023S 037W KEARNY KS HOOVER, HELEN 1-A 046811111 COLORADO INTERSTATE GAS CO
007 029S 034W HASKELL KS HOWELL A-2 046980111 COLORADO INTERSTATE GAS CO
007 029S 034W HASKELL KS HOWELL 1 046910111 COLORADO INTERSTATE GAS CO
011 029S 032W HASKELL KS HOWELL 1 046960111 COLORADO INTERSTATE GAS CO
007 029S 034W HASKELL KS HOWELL A-3 046981111 COLORADO INTERSTATE GAS CO
008 029S 033W HASKELL KS HUITT 1 047310111 COLORADO INTERSTATE GAS CO
001 030S 032W HASKELL KS HUXMAN B-1 047610111 COLORADO INTERSTATE GAS CO
014 030S 032W HASKELL KS IHLOFF A-1 048660111 COLORADO INTERSTATE GAS CO
003 026S 031W FINNEY KS IRRIG. LAND DEVELOP. 1 048905111 COLORADO INTERSTATE GAS CO
014 023S 035W KEARNY KS JAMES 1 049260111 COLORADO INTERSTATE GAS CO
005 027S 036W GRANT KS JARVIS 1 049360111 COLORADO INTERSTATE GAS CO
030 029S 036W GRANT KS JARVIS 1 049410111 COLORADO INTERSTATE GAS CO
030 029S 036W GRANT KS JARVIS 2 049430111 COLORADO INTERSTATE GAS CO
030 029S 036W GRANT KS JARVIS UNIT 3 049435111 COLORADO INTERSTATE GAS CO
019 029S 036W GRANT KS JARVIS WATKINS 1 049460111 COLORADO INTERSTATE GAS CO
019 029S 036W GRANT KS JARVIS-WATKINS 2 049470111 COLORADO INTERSTATE GAS CO
005 027S 036W GRANT KS JARVIS/PHELPS DELIVERY 049361000 COLORADO INTERSTATE GAS CO
024 025S 037W KEARNY KS JOHNSON 2 050210111 COLORADO INTERSTATE GAS CO
018 025S 036W KEARNY KS JOHNSON 3 050260111 COLORADO INTERSTATE GAS CO
019 025S 036W KEARNY KS JOHNSON 4 050310111 COLORADO INTERSTATE GAS CO
013 025S 037W KEARNY KS JOHNSON CDP 049960000 COLORADO INTERSTATE GAS CO
018 025S 036W KEARNY KS JOHNSON CG 5 050340111 COLORADO INTERSTATE GAS CO
013 025S 037W KEARNY KS JOHNSON/CG 1-A 049961111 COLORADO INTERSTATE GAS CO
024 025S 037W KEARNY KS JOHNSON/CG 2-A 050211111 COLORADO INTERSTATE GAS CO
019 025S 036W KEARNY KS JOHNSON/CG 4-A 050311111 COLORADO INTERSTATE GAS CO
003 028S 034W HASKELL KS JONES C-1 051110111 COLORADO INTERSTATE GAS CO
001 027S 035W GRANT KS JONES F-1 051160111 COLORADO INTERSTATE GAS CO
034 026S 034W FINNEY KS JONES 1 050460111 COLORADO INTERSTATE GAS CO
036 026S 035W KEARNY KS JONES 2 050510111 COLORADO INTERSTATE GAS CO
033 026S 034W FINNEY KS JONES 3 050560111 COLORADO INTERSTATE GAS CO
032 026S 034W FINNEY KS JONES 4 050610111 COLORADO INTERSTATE GAS CO
030 026S 034W FINNEY KS JONES 5 050660111 COLORADO INTERSTATE GAS CO
029 026S 034W FINNEY KS JONES 6 050710111 COLORADO INTERSTATE GAS CO
018 027S 034W HASKELL KS JONES 7 050760111 COLORADO INTERSTATE GAS CO
005 027S 034W HASKELL KS JONES 8 050810111 COLORADO INTERSTATE GAS CO
004 027S 034W HASKELL KS JONES 9 050860111 COLORADO INTERSTATE GAS CO
008 027S 034W HASKELL KS JONES E-1 051150111 COLORADO INTERSTATE GAS CO
001 027S 035W GRANT KS JONES F-2 051161111 COLORADO INTERSTATE GAS CO
030 026S 034W FINNEY KS JONES G-1 051170111 COLORADO INTERSTATE GAS CO
005 027S 034W HASKELL KS JONES H-1 051180111 COLORADO INTERSTATE GAS CO
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLORADO INTERSTATE GAS COMPANY
MASTER LIST OF GATHERING RECEIPT POINTS
AS OF 09/10/93
HUGOTON/PANOMA AREA G 2 LAM
COUNTY LOCATION
SECTION TOWNSHIP RANGE NAME STATE WELL NAME NUMBER MEASURING PARTY
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
029 026S 034W FINNEY KS JONES I-1 051190111 COLORADO INTERSTATE GAS CO
036 026S 035W KEARNY KS JONES J-1 051200111 COLORADO INTERSTATE GAS CO
004 027S 034W HASKELL KS JONES K-1 051201111 COLORADO INTERSTATE GAS CO
015 027S 034W HASKELL KS JONES L-1 051202111 COLORADO INTERSTATE GAS CO
032 026S 034W FINNEY KS JONES M-1 051203111 COLORADO INTERSTATE GAS CO
034 026S 034W FINNEY KS JONES N-1 051204111 COLORADO INTERSTATE GAS CO
033 026S 034W FINNEY KS JONES P-1 051206111 COLORADO INTERSTATE GAS CO
018 027S 034W HASKELL KS JONES Q-1 051207111 COLORADO INTERSTATE GAS CO
007 027S 034W HASKELL KS JONES R-1 051208111 COLORADO INTERSTATE GAS CO
010 027S 034W HASKELL KS JONES U-1 051212111 COLORADO INTERSTATE GAS CO
003 027S 034W HASKELL KS JONES 10 050910111 COLORADO INTERSTATE GAS CO
008 027S 034W HASKELL KS JONES 11 050960111 COLORADO INTERSTATE GAS CO
010 027S 034W HASKELL KS JONES 12 051010111 COLORADO INTERSTATE GAS CO
022 023S 035W KEARNY KS JONES UNIT C-1 051210111 COLORADO INTERSTATE GAS CO
010 027S 034W HASKELL KS JONES 12-2 051015111 COLORADO INTERSTATE GAS CO
036 026S 035W KEARNY KS JONES 2-2 050515111 COLORADO INTERSTATE GAS CO
007 027S 034W HASKELL KS JONES-LADNER 13 051060111 COLORADO INTERSTATE GAS CO
004 029S 032W HASKELL KS KAIN #2 051825111 COLORADO INTERSTATE GAS CO
009 026S 031W FINNEY KS KELLER B-1 052470111 COLORADO INTERSTATE GAS CO
017 026S 031W FINNEY KS KELLER 1 052370111 COLORADO INTERSTATE GAS CO
029 029S 036W GRANT KS KELLER ERNEST 1 052520111 COLORADO INTERSTATE GAS CO
029 029S 036W GRANT KS KELLER ERNEST 2 052530111 COLORADO INTERSTATE GAS CO
029 027S 034W HASKELL KS KELLS C-2 052570111 COLORADO INTERSTATE GAS CO
029 027S 034W HASKELL KS KELLS C-3 052571111 COLORADO INTERSTATE GAS CO
029 027S 034W HASKELL KS KELLS C-4 052572111 COLORADO INTERSTATE GAS CO
031 024S 037W KEARNY KS KENDALL EXCHANGE 065556100 GREELEY GAS COMPANY
016 023S 036W KEARNY KS KLEEMAN 1 053970111 COLORADO INTERSTATE GAS CO
016 023S 036W KEARNY KS KLEEMAN E L 2 053980111 COLORADO INTERSTATE GAS CO
030 026S 031W FINNEY KS KLEYSTEUBER 1 054020111 COLORADO INTERSTATE GAS CO
012 029S 034W HASKELL KS KOENIG (CSGH) 1 054270111 COLORADO INTERSTATE GAS CO
017 024S 037W KEARNY KS KREHBIEL 1 053870111 COLORADO INTERSTATE GAS CO
017 024S 037W KEARNY KS KREHBIEL 1-A 054300111 COLORADO INTERSTATE GAS CO
024 026S 040W HAMILTON KS KRITZMIRE 054320111 COLORADO INTERSTATE GAS CO
024 026S 040W HAMILTON KS KRITZMIRE 3 054340111 COLORADO INTERSTATE GAS CO
018 24S 38W KEARNY KS KURZ A-1&BURNETT 1-18R 054365000 ANADARKO PETROLEUM CORP
030 028S 033W HASKELL KS LAIRD B-1 054690111 COLORADO INTERSTATE GAS CO
035 026S 040W HAMILTON KS LAKE UNIT 1 054810111 COLORADO INTERSTATE GAS CO
029 024S 036W KEARNY KS LAKIN PURCHASE (EG CMP)065865111 NOT APPLICABLE]
008 026S 039W HAMILTON KS LAMPE 1 054940111 COLORADO INTERSTATE GAS CO
008 026S 039W HAMILTON KS LAMPE J 2-8 054900111 COLORADO INTERSTATE GAS CO
010 026S 039W HAMILTON KS LAMPE JOHN 1 054990111 COLORADO INTERSTATE GAS CO
010 026S 039W HAMILTON KS LAMPE JOHN 2-10 054995111 COLORADO INTERSTATE GAS CO
019 027S 040W STANTON KS LANE 1 055000111 COLORADO INTERSTATE GAS CO
032 025S 034W FINNEY KS LEE 1 055190111 COLORADO INTERSTATE GAS CO
015 026S 037W KEARNY KS LEE 2 055191111 COLORADO INTERSTATE GAS CO
032 025S 034W FINNEY KS LEE 2 055192111 COLORADO INTERSTATE GAS CO
015 026S 037W KEARNY KS LEE T P 1 055240111 COLORADO INTERSTATE GAS CO
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLORADO INTERSTATE GAS COMPANY
MASTER LIST OF GATHERING RECEIPT POINTS
AS OF 09/10/93
HUGOTON/PANOMA AREA G 2 LAM
COUNTY LOCATION
SECTION TOWNSHIP RANGE NAME STATE WELL NAME NUMBER MEASURING PARTY
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
024 028S 034W HASKELL KS LEMON A-1 055390111 COLORADO INTERSTATE GAS CO
025 028S 034W HASKELL KS LEMON B-1 055440111 COLORADO INTERSTATE GAS CO
009 029S 033W HASKELL KS LEMON C-1 055490111 COLORADO INTERSTATE GAS CO
008 029S 033W HASKELL KS LEMON 1 055310111 COLORADO INTERSTATE GAS CO
025 028S 034W HASKELL KS LEMON 1-25 055300111 COLORADO INTERSTATE GAS CO
024 028S 034W HASKELL KS LEMON A-2 055391111 COLORADO INTERSTATE GAS CO
001 029S 034W HASKELL KS LIGHT D-1 055960111 COLORADO INTERSTATE GAS CO
002 029S 034W HASKELL KS LIGHT (MOR) C-1 055950111 COLORADO INTERSTATE GAS CO
008 026S 031W FINNEY KS LIGHTNER 1 055990111 COLORADO INTERSTATE GAS CO
031 029S 036W GRANT KS LIMPER D 2 056030111 COLORADO INTERSTATE GAS CO
031 029S 036W GRANT KS LIMPER DOROTHY 1 056040111 COLORADO INTERSTATE GAS CO
005 24W 38W KEARNY KS LINDNER A-1&LINDNER 1-5056095000 ANADARKO PETROLEUM CORP
025 025S 039W HAMILTON KS LINDSAY 1 056090111 COLORADO INTERSTATE GAS CO
014 026S 034W FINNEY KS LOCKWOOD 1 056290111 COLORADO INTERSTATE GAS CO
014 026S 034W FINNEY KS LOCKWOOD 2 056291111 COLORADO INTERSTATE GAS CO
014 026S 034W FINNEY KS LOCKWOOD 3-14 056292111 COLORADO INTERSTATE GAS CO
035 023S 037W KEARNY KS LONGWOOD 1-2 056691111 COLORADO INTERSTATE GAS CO
018 024S 036W KEARNY KS LOUCKS A-1 057040111 COLORADO INTERSTATE GAS CO
018 024S 036W KEARNY KS LOUCKS A-2 057041111 COLORADO INTERSTATE GAS CO
008 024S 036W KEARNY KS LOUCKS B-1 057090111 COLORADO INTERSTATE GAS CO
008 024S 036W KEARNY KS LOUCKS B-2 057091111 COLORADO INTERSTATE GAS CO
031 023S 036W KEARNY KS LOUCKS 1 056890111 COLORADO INTERSTATE GAS CO
007 024S 036W KEARNY KS LOUCKS 2 056940111 COLORADO INTERSTATE GAS CO
001 024S 037W KEARNY KS LOUCKS 3 056990111 COLORADO INTERSTATE GAS CO
031 023S 036W KEARNY KS LOUCKS 4 056991111 COLORADO INTERSTATE GAS CO
007 024S 036W KEARNY KS LOUCKS 5 056992111 COLORADO INTERSTATE GAS CO
001 024S 037W KEARNY KS LOUCKS 6 056993111 COLORADO INTERSTATE GAS CO
001 024S 037W KEARNY KS LOUCKS,C.A. NO. 7 056994111 COLORADO INTERSTATE GAS CO
009 028S 034W HASKELL KS MACE A-2 058009111 COLORADO INTERSTATE GAS CO
009 028S 034W HASKELL KS MACE 1 058010111 COLORADO INTERSTATE GAS CO
009 028S 034W HASKELL KS MACE A-3 058008111 COLORADO INTERSTATE GAS CO
034 027S 040W STANTON KS MAHONEY 1 070760111 COLORADO INTERSTATE GAS CO
034 027S 040W STANTON KS MAHONEY 2-34 070761111 COLORADO INTERSTATE GAS CO
035 022S 033W FINNEY KS MANNS 1 058110111 COLORADO INTERSTATE GAS CO
012 030S 032W HASKELL KS MARSHALL 1 058660111 COLORADO INTERSTATE GAS CO
016 029S 040W STANTON KS MARTIN GU 1 058675111 COLORADO INTERSTATE GAS CO
012 027S 032W HASKELL KS MATHES A-1 062080111 COLORADO INTERSTATE GAS CO
006 027S 031W HASKELL KS MATHES B-1 062160111 COLORADO INTERSTATE GAS CO
026 029S 032W HASKELL KS MC CLURE B-1 064240111 COLORADO INTERSTATE GAS CO
025 029S 032W HASKELL KS MC CLURE 1 064160111 COLORADO INTERSTATE GAS CO
002 030S 032W HASKELL KS MC COY 1 064400111 COLORADO INTERSTATE GAS CO
032 028S 034W HASKELL KS MC COY 1 064480111 COLORADO INTERSTATE GAS CO
032 028S 034W HASKELL KS MC COY 4-32 064495111 COLORADO INTERSTATE GAS CO
013 025S 039W HAMILTON KS MC DONALD 1 064720111 COLORADO INTERSTATE GAS CO
013 025S 039W HAMILTON KS MC DONALD 2 064725111 COLORADO INTERSTATE GAS CO
004 026S 031W FINNEY KS MC GRAW 1 065040111 COLORADO INTERSTATE GAS CO
028 026S 034W FINNEY KS MC KEE A-1 065281111 COLORADO INTERSTATE GAS CO
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLORADO INTERSTATE GAS COMPANY
MASTER LIST OF GATHERING RECEIPT POINTS
AS OF 09/10/93
HUGOTON/PANOMA AREA G 2 LAM
COUNTY LOCATION
SECTION TOWNSHIP RANGE NAME STATE WELL NAME NUMBER MEASURING PARTY
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
028 026S 034W FINNEY KS MC KEE 1 065280111 COLORADO INTERSTATE GAS CO
007 026S 039W HAMILTON KS MESA-LOWENBERG 1-7 068570111 COLORADO INTERSTATE GAS CO
028 023S 035W KEARNY KS MILLER J-1 070160111 COLORADO INTERSTATE GAS CO
013 021S 035W KEARNY KS MILLER 1 070002111 COLORADO INTERSTATE GAS CO
028 023S 035W KEARNY KS MILLER J-2 070161111 COLORADO INTERSTATE GAS CO
003 024S 036W KEARNY KS MILLYARD 1 070460111 COLORADO INTERSTATE GAS CO
003 024S 036W KEARNY KS MILLYARD 2 070461111 COLORADO INTERSTATE GAS CO
003 024S 036W KEARNY KS MILLYARD A. FARM UNIT 3070465111 COLORADO INTERSTATE GAS CO
034 025S 031W FINNEY KS MINTER-WILSON 1 070665111 NORTHERN NATURAL GASPROD
004 023S 037W KEARNY KS MODIE 1 070710111 COLORADO INTERSTATE GAS CO
004 023S 037W KEARNY KS MODIE 1-A 070711111 COLORADO INTERSTATE GAS CO
034 027S 040W STANTON KS MOHNEY 3-34 070812111 COLORADO INTERSTATE GAS CO
003 024S 035W KEARNY KS MOLZ 1 070860111 COLORADO INTERSTATE GAS CO
029 025S 033W FINNEY KS MOODY 1 071060111 COLORADO INTERSTATE GAS CO
029 025S 033W FINNEY KS MOODY 2 071061111 COLORADO INTERSTATE GAS CO
003 029S 034W HASKELL KS MOODY C-2 (CSGHD) 026745111 COLORADO INTERSTATE GAS CO
003 029S 034W HASKELL KS MOODY C-3 071165111 COLORADO INTERSTATE GAS CO
003 029S 034W HASKELL KS MOODY CHE A-1-3071170111 COLORADO INTERSTATE GAS CO
005 026S 034W FINNEY KS MOODY WM 1 071360111 COLORADO INTERSTATE GAS CO
005 026S 034W FINNEY KS MOODY WM GAS UNIT 2 071361111 COLORADO INTERSTATE GAS CO
002 024S 035W KEARNY KS MURRAY B-1 072410111 COLORADO INTERSTATE GAS CO
008 028S 040W STANTON KS NICHOLAS GAS UNIT 1-8 074375111 COLORADO INTERSTATE GAS CO
013 027S 032W HASKELL KS NICHOLS 1 074380111 COLORADO INTERSTATE GAS CO
016 026S 034W FINNEY KS NOLAN 1 074480111 COLORADO INTERSTATE GAS CO
016 026S 034W FINNEY KS NOLAN GAS UNIT 2 074481111 COLORADO INTERSTATE GAS CO
016 026S 034W FINNEY KS NOLAN 4-16 074483111 COLORADO INTERSTATE GAS CO
031 021S 034W FINNEY KS NORRIS 1 074490111 COLORADO INTERSTATE GAS CO
001 029S 037W GRANT KS OCKULY 1 074910111 COLORADO INTERSTATE GAS CO
001 029S 037W GRANT KS OCKULY (CG) 2 074912111 COLORADO INTERSTATE GAS CO
012 021S 035W KEARNY KS ODD WILLIAMS 2 074914111 COLORADO INTERSTATE GAS CO
014 027S 034W HASKELL KS OLIVER 1 074960111 COLORADO INTERSTATE GAS CO
015 027S 034W HASKELL KS OLIVER "A" 2 074965111 COLORADO INTERSTATE GAS CO
002 029S 034W HASKELL KS ONIONS 1 075060111 COLORADO INTERSTATE GAS CO
021 028S 033W HASKELL KS ORTH 1 075110111 COLORADO INTERSTATE GAS CO
021 028S 033W HASKELL KS ORTH A-2 075115111 COLORADO INTERSTATE GAS CO
007 030S 031W HASKELL KS OSBORN 2 075160111 COLORADO INTERSTATE GAS CO
034 025S 039W HAMILTON KS OVERBEY GAS UNIT 1 075201111 COLORADO INTERSTATE GAS CO
034 025S 039W HAMILTON KS OVERBEY GAS UNIT 2 075202111 COLORADO INTERSTATE GAS CO
034 023S 035W KEARNY KS PARKER 1 075660111 COLORADO INTERSTATE GAS CO
034 023S 035W KEARNY KS PARKER A-2 075661111 COLORADO INTERSTATE GAS CO
004 024S 037W KEARNY KS PEMBERTON 1 076210111 COLORADO INTERSTATE GAS CO
004 024S 037W KEARNY KS PEMBERTON 1-A 076211111 COLORADO INTERSTATE GAS CO
006 027S 036W GRANT KS PHELPS 1 076410111 COLORADO INTERSTATE GAS CO
006 027S 036W GRANT KS PHELPS/CG 1-A 076411111 COLORADO INTERSTATE GAS CO
031 028S 034W HASKELL KS PICKENS A-2 076751111 COLORADO INTERSTATE GAS CO
031 028S 034W HASKELL KS PICKENS 1 076760111 COLORADO INTERSTATE GAS CO
035 027S 040W STANTON KS PIPER 1 076774111 COLORADO INTERSTATE GAS CO
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLORADO INTERSTATE GAS COMPANY
MASTER LIST OF GATHERING RECEIPT POINTS
AS OF 09/10/93
HUGOTON/PANOMA AREA G 2 LAM
COUNTY LOCATION
SECTION TOWNSHIP RANGE NAME STATE WELL NAME NUMBER MEASURING PARTY
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
035 027S 040W STANTON KS PIPER 2-A 076775111 COLORADO INTERSTATE GAS CO
011 027S 040W STANTON KS PLUMMER A-1 076860111 COLORADO INTERSTATE GAS CO
011 027S 040W STANTON KS PLUMMER A-2 076861111 COLORADO INTERSTATE GAS CO
015 027S 040W STANTON KS PLUMMER B-1 076910111 COLORADO INTERSTATE GAS CO
015 027S 040W STANTON KS PLUMMER B-2 076911111 COLORADO INTERSTATE GAS CO
010 027S 040W STANTON KS PLUMMER C-1 076960111 COLORADO INTERSTATE GAS CO
010 027S 040W STANTON KS PLUMMER C-2 076961111 COLORADO INTERSTATE GAS CO
005 028S 040W STANTON KS PLUMMER D-1 077010111 COLORADO INTERSTATE GAS CO
005 028S 040W STANTON KS PLUMMER D-2 077011111 COLORADO INTERSTATE GAS CO
009 029S 040W STANTON KS PLUMMER 1 076858111 COLORADO INTERSTATE GAS CO
022 029S 040W STANTON KS PLUMMER GU E-1 076857111 COLORADO INTERSTATE GAS CO
016 028S 033W HASKELL KS PORTER #1 077155111 COLORADO INTERSTATE GAS CO
027 026S 035W KEARNY KS POTTER A-1 077212111 COLORADO INTERSTATE GAS CO
026 026S 035W KEARNY KS POTTER 1 077210111 COLORADO INTERSTATE GAS CO
016 030S 033W HASKELL KS R A JAMES B UN 049270111 COLORADO INTERSTATE GAS CO
013 024S 037W KEARNY KS R. L. GREEN NO. 3 039582111 COLORADO INTERSTATE GAS CO
003 029S 034W HASKELL KS RAHENKAMP 1 078030111 COLORADO INTERSTATE GAS CO
003 029S 034W HASKELL KS RAHENKAMP A 2 078035111 COLORADO INTERSTATE GAS CO
033 028S 040W STANTON KS RAMSAY A-1 078227111 COLORADO INTERSTATE GAS CO
021 028S 040W STANTON KS RAMSAY 1 078228111 COLORADO INTERSTATE GAS CO
021 023S 036W KEARNY KS RATZLAFF A-1 078470111 COLORADO INTERSTATE GAS CO
028 023S 036W KEARNY KS RATZLAFF B-1 078510111 COLORADO INTERSTATE GAS CO
001 025S 037W KEARNY KS RATZLAFF 1 078350111 COLORADO INTERSTATE GAS CO
010 024S 036W KEARNY KS RATZLAFF 2 078430111 COLORADO INTERSTATE GAS CO
001 025S 037W KEARNY KS RATZLAFF 4-1 078440111 COLORADO INTERSTATE GAS CO
021 023S 036W KEARNY KS RATZLAFF D A-2 078540111 COLORADO INTERSTATE GAS CO
021 023S 036W KEARNY KS RATZLAFF D B-2 078541111 COLORADO INTERSTATE GAS CO
016 023S 036W KEARNY KS RATZLAFF D "A" NO. 3 078436111 COLORADO INTERSTATE GAS CO
028 023S 036W KEARNY KS RATZLAFF DAN UNIT D-1 078550111 COLORADO INTERSTATE GAS CO
010 024S 036W KEARNY KS RATZLAFF 2 2-10 078435111 COLORADO INTERSTATE GAS CO
004 026S 039W HAMILTON KS RECTOR 2-4 078929111 COLORADO INTERSTATE GAS CO
004 026S 039W HAMILTON KS RECTOR O 1 078930111 COLORADO INTERSTATE GAS CO
033 025S 039W HAMILTON KS RECTOR O E 1 074700111 COLORADO INTERSTATE GAS CO
004 026S 039W HAMILTON KS RECTOR 3-4 078928111 COLORADO INTERSTATE GAS CO
007 026S 034W FINNEY KS REEVE 1 078990111 COLORADO INTERSTATE GAS CO
032 025S 034W FINNEY KS REEVE FEDERAL 32-2 058088111 COLORADO INTERSTATE GAS CO
007 026S 034W FINNEY KS REEVE GAS UNIT 2 078991111 COLORADO INTERSTATE GAS CO
007 026S 034W FINNEY KS REEVE 4-7 078993111 COLORADO INTERSTATE GAS CO
030 025S 034W FINNEY KS REEVES A-1 079071111 COLORADO INTERSTATE GAS CO
018 026S 034W FINNEY KS REEVES 1 079030111 COLORADO INTERSTATE GAS CO
030 025S 034W FINNEY KS REEVES 2 079070111 COLORADO INTERSTATE GAS CO
025 028S 032W HASKELL KS REIMELT 1 079150111 COLORADO INTERSTATE GAS CO
035 028S 034W HASKELL KS REIMER A-2 079110111 COLORADO INTERSTATE GAS CO
014 031S 032W SEWARD KS RICHARDSON F-1 079305111 COLORADO INTERSTATE GAS CO
006 026S 033W FINNEY KS RIGG UNIT 1 079390111 COLORADO INTERSTATE GAS CO
006 026S 033W FINNEY KS RIGGS A-1 079455111 COLORADO INTERSTATE GAS CO
005 026S 033W FINNEY KS RIGGS 1-2 079395111 COLORADO INTERSTATE GAS CO
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
COLORADO INTERSTATE GAS COMPANY
MASTER LIST OF GATHERING RECEIPT POINTS
AS OF 09/10/93
HUGOTON/PANOMA AREA G 2 LAM
COUNTY LOCATION
SECTION TOWNSHIP RANGE NAME STATE WELL NAME NUMBER MEASURING PARTY
- -----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
004 025S 036W KEARNY KS ROBINSON C-1 079590111 COLORADO INTERSTATE GAS CO
004 025S 036W KEARNY KS ROBINSON C-2 079591111 COLORADO INTERSTATE GAS CO
033 024S 037W KEARNY KS ROBRAHN 1 079630111 COLORADO INTERSTATE GAS CO
033 024S 037W KEARNY KS ROBRAHN E E 2 079635111 COLORADO INTERSTATE GAS CO
031 030S 031W HASKELL KS ROONEY 1 079830111 COLORADO INTERSTATE GAS CO
024 031S 032W SEWARD KS ROSSON 1 079990111 COLORADO INTERSTATE GAS CO
027 027S 033W HASKELL KS ROY 3 080070111 COLORADO INTERSTATE GAS CO
034 027S 033W HASKELL KS ROY 5 080150111 COLORADO INTERSTATE GAS CO
033 027S 033W HASKELL KS ROY 6 080190111 COLORADO INTERSTATE GAS CO
033 027S 033W HASKELL KS ROY 10-33 080196111 COLORADO INTERSTATE GAS CO
034 027S 033W HASKELL KS ROY 11-34 080197111 COLORADO INTERSTATE GAS CO
027 027S 033W HASKELL KS ROY 9-27 080195111 COLORADO INTERSTATE GAS CO
028 029S 036W GRANT KS S. HAGERMAN UNIT 3 041327111 COLORADO INTERSTATE GAS CO
034 023S 037W KEARNY KS SALYER 1 081450111 COLORADO INTERSTATE GAS CO
027 023S 037W KEARNY KS SALYER 1-2 081451111 COLORADO INTERSTATE GAS CO
018 013S 032W SEWARD KS SATTERFIELD/GARTEN 991722000 COLORADO INTERSTATE GAS CO
018 031S 032W SEWARD KS SATTERFIELD/GARTEN (GATH)991722121 NOT APPLICABLE
015 023S 037W KEARNY KS SAUER B-1 082470111 COLORADO INTERSTATE GAS CO
015 023S 037W KEARNY KS SAUER B-2 082471111 KN ENERGY INC
025 023S 037W KEARNY KS SAUER 1 082290111 COLORADO INTERSTATE GAS CO
025 023S 037W KEARNY KS SAUER 1-A 082291111 COLORADO INTERSTATE GAS CO
028 025S 033W FINNEY KS SCHEER 1 082950111 COLORADO INTERSTATE GAS CO
028 025S 033W FINNEY KS SCHEER 2 082951111 COLORADO INTERSTATE GAS CO
028 025S 033W FINNEY KS SCHEER 3-28 082952111 COLORADO INTERSTATE GAS CO
006 031S 031W SEWARD KS SCHMIDT B-1 083070111 COLORADO INTERSTATE GAS CO
007 031S 031W SEWARD KS SCHMIDT 1 083010111 COLORADO INTERSTATE GAS CO
007 031S 031W SEWARD KS SCHMIDT 1 083011111 COLORADO INTERSTATE GAS CO
012 031S 032W SEWARD KS SCHMIDT, LUTHER 1 057540111 COLORADO INTERSTATE GAS CO
005 029S 036W GRANT KS SCHWEIN A-1 083730111 COLORADO INTERSTATE GAS CO
005 029S 036W GRANT KS SCHWEIN A-2 083731111 COLORADO INTERSTATE GAS CO
005 029S 036W GRANT KS SCHWEIN A-3 083732111 COLORADO INTERSTATE GAS CO
001 027S 035W GRANT KS SHAWVER 1 084750111 COLORADO INTERSTATE GAS CO
002 027S 035W GRANT KS SHAWVER 2-2 084751111 COLORADO INTERSTATE GAS CO
024 023S 035W KEARNY KS SHELL 1 084990111 COLORADO INTERSTATE GAS CO
018 025S 037W KEARNY KS SHELL 1 085050111 COLORADO INTERSTATE GAS CO
024 023S 035W KEARNY KS SHELL A-2 085010111 COLORADO INTERSTATE GAS CO
018 025S 037W KEARNY KS SHELL 1-2-18 085051111 COLORADO INTERSTATE GAS CO
033 025S 034W FINNEY KS SINN 1 085290111 COLORADO INTERSTATE GAS CO
033 025S 034W FINNEY KS SINN 2 085291111 COLORADO INTERSTATE GAS CO
033 025S 034W FINNEY KS SINN 3-33 085292111 COLORADO INTERSTATE GAS CO
026 027S 040W STANTON KS SMITH A E 1 086010111 COLORADO INTERSTATE GAS CO
026 027S 040W STANTON KS SMITH A E 2-26 086011111 COLORADO INTERSTATE GAS CO
026 027S 040W STANTON KS SMITH 3-26 086012111 COLORADO INTERSTATE GAS CO
022 027S 034W HASKELL KS SNIDER B-1 087810111 COLORADO INTERSTATE GAS CO
032 027S 034W HASKELL KS STANLEY A-2 088831111 COLORADO INTERSTATE GAS CO
032 027S 034W HASKELL KS STANLEY 1 088830111 COLORADO INTERSTATE GAS CO
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
09/20/93
COLORADO INTERSTATE GAS COMPANY
GATHERING DELIVERY POINTS
MAXIMUM
COUNTY LOCATION MEASURING PRESSURE
SECTION TOWNSHIP RANGE NAME STATE DELIVERY NAME AGGREGATE NUMBER PARTY (p.s.i.g.)
- ------- -------- ----- ------------ ----- --------------------- ------------ -------- --------- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
36 20N 103W SWEETWATER WY ABB RECEIPT M 1 ABM 991650000 NMS 845
21 23S 34E LEA NM ANTELOPE RIDGE O 9 ANT 991136000 CIG 960
363 PMC 3&LRR MOORE TX BIVINS MASTER METER M 3 BIM 991143100 CIG 250
29 36N 89W FREMONT WY BULLFROG/TEPEE FLATS M 1 BUL 066153000 NMS 1100
5 24N 96W SWEETWATER WY BUSH LAKE DELIVERY O 9 BSH 021785100 CIG 1000
32 T21N R34W FINNEY KS CAMPBELL DRAW DELIVERY O 9 CDE 991177000 CIG 500
13 18S 45W KIOWA CO CAVALRY RECEIPT M 2 CAV 991702000 NMS 850
18 3N 26E BEAVER OK CLEAR LAKE O 9 CLL 991179000 CIG 500
9 19N 98W SWEETWATER WY DESERT SPRINGS MASTER M 1 DES 991145100 CIG 845
15 1N 26E BEAVER OK DURFEY O 9 DUR 931180000 NMS 500
34 20N 101W SWEETWATER WY EAST ROCK SPRINGS M 1 ERS 991701000 NMS 845
8 20N 92W SWEETWATER WY ECHO SPRINGS MASTER M 1 ECH 991165100 CIG 850
9 18S 45W KIOWA CO FLUKE TIE-IN M 2 FLU 991570000 NMS 850
7 36N 93W FREEMONT WY FULLER WIND RIVER M 1 FWR 991524100 NMS 960
18 33S 43W MORTON KS GREENWOOD MASTER METER M 3 GRW 991159100 CIG 761
13 25S 36W KEARNY KS HUGOTON/KNE EXCHANGE 0 9 HKE 991181000 CIG 240
29 25S 35W KEARNY KS H&P SUNFLOWER O 9 HPS 991652000 CIG 300
17 10S 23E UNITAH UT KAYE STATE O 9 KAY 991667000 CHEVRON 960
17 5N 7E CIMARRON OK KEYES MASTER METER M 3 KEY 991155100 CIG 550
29 24S 36W KEARNY KS LAKIN MASTER METER M 2 LAM 065864000 CIG 920
33 19S 48W KIOWA CO LEFT HAND (WEAR TRUST) M 2 LEF 991675000 NMS 924
11 38N 90W FREMONT WY LOST CABIN M 1 LOS 066156000 CIG 1100
2 38N 90W FREMONT WY MADDEN EXCHANGE (KN) O 9 MKN 058100111 CIG 960
30 20N 101W SWEETWATER WY MASTERSON M 1 MAS 991726000 NMS N/A
31 5N 24E BEAVER OK MILES G-1 O 9 MG1 069660000 NMS 500
18 5N 25E BEAVER OK MOCANE WARREN PLANT M 3 MOC 991106000 CIG 500
8 24N 96W SWEETWATER WY NICKEY FIELD EXCHANGE O 9 NKY 991116000 CIG 960
5 51N 100W PARK WY NORTH OREGON BASIN M 1 MOB 991651000 NMS 1200
9 22S 37W KEARNY KS PANOMA/NNG INTERCONNECTO 9 NNG 066304000 NMS 500
36 20N 101W SWEETWATER WY POINT OF ROCKS M 1 PTR 991679000 NMS 845
8 19N 91W CARBON WY PORTER FEDERAL DELIVERYO 9 PRD 077150000 NMS 960
13 12N 16W CUSTER OK RED HILLS DELIVERY O 9 REH 991623000 NMS 960
10 23S 38W KEARNY KS RINHART/KJA O 9 RIN 991756000 NMS 960
20 9S 20E UINTAH UT SALT WATER DISPOSAL O 9 H2O 073000000 CIG 960
2 2S 55W WASHINGTON CO SHARP 1 O 9 WDR 065787000 CIG 960
23 21N 99W MOFFAT CO SHELL CREEK DELIVERY O 9 SCR 085080000 NMS 960
12 19N 98W SWEETWATER WY TABLE ROCK MASTER METERM 1 TAB 991173100 CIG 850
23 19N 98W SWEETWATER WY TABLE ROCK RESIDUE M 1 TRR 991163000 CIG 845
28 6N 10E TEXAS OK TEDROW DELIVERY O 9 TED 092420000 NMS 500
27 20N 97W SWEETWATER WY TIPTON M 1 TIP 991737000 NMS 845
24 9S 21E UINTAH UT UINTAH M 1 UIN 991764000 CIG 1050
23 31S 45W BACA CO VILAS MASTER METER M 3 VIL 991172100 CIG 500
31 20N 94W SWEETWATER WY WAMSUTTER MASTER METER M 1 WAM 991164100 CIG 845
2 8LL JMLS WHEELER TX WHEELER EXCHANGE O 9 WLR 991188000 CIG 960
3 CPCO SCHL WHEELER TX WILLIS METER STATION O 9 WMS 991043000 CIG 960
</TABLE>
<PAGE>
<PAGE>
APPENDIX "A"
AMENDMENT DATED January 1, 1994
to
GAS GATHERING AGREEMENT
DATED October 1, 1993
between
COLORADO INTERSTATE GAS COMPANY
and
MESA OPERATING CO.
ACTING ON BEHALF OF ITSELF AND AS AGENT FOR
HUGOTON CAPITAL LIMITED PARTNERSHIP
Gathering Rates
Commodity
Point(s) of Rates Fuel
Gathering Area Delivery (Notes 1 & 2) (Note 3) Term of Rate
- -------------- --------------- ------------- -------- -----------------
Hugoton Lakin Master $0.1540
Meter per Dth 3.00% 10/1/93-1/29/95
Lakin Master Base Rate I 3.00% 1/30/95-1/31/2010
Meter (Note 5) (Note 4)
Plus IFUR
Note 6)
Plus
$0.025
per Dth
KN Exchange $0.1850
per Dth 3.00% 10/1/93-9/30/94
KN Exchange $0.1665 3.00% 10/1/94-1/29/95
per Dth
H&P Sunflower $0.1850
per Dth 3.00% 10/1/93-9/30/94
H&P Sunflower $0.1665 3.00% 10/1/94-1/29/95
per Dth
Hugoton Satanta Base Rate I 3.00% 1/30/95-1/31/2010
(Exhibit "B", (Note 5) (Note 4)
Schedule 1 & 2 Plus IFUR
Wells) (Note 6)
Hugoton Satanta Base Rate I 3.00% 5/01/95-5/31/95
Exhibit "B" (for Dth transported (Note 5)
Schedule 1 & 2 by Northern Natural Plus IFUR
Wells) Gas Company for (Note 6)
Transporter)
Hugoton Satanta Base Rate II (Note 7)(Notes 4 and 7)
(Exhibit "B", (Note 7)
Schedule 3 Plus IFUR
Wells) (Note 6)
<PAGE>
APPENDIX "A"
NOTES: (1) The Commodity Rate for service hereunder shall be as agreed
between the Parties, except that in the event that an
effective rate for service in a gathering area is not agreed
to prior to the tender of gas by Shipper for service in that
gathering area, then the rate for that service, until
otherwise agreed, shall be the maximum rate that Transporter
charges for gathering service in that area.
(2) The wells under Footnote 4 of Exhibit "B", Schedule 1, are
subject to a reduction of 1.3 cents per Dth, as described in
the Letter Agreement between Shipper and Transporter dated
January 5, 1994. Invoicing procedures shall be governed by
Transporter's January 17, 1994 Letter to Shipper.
(3) The Fuel Percentage shall be adjusted from time to time
throughout the term of the Agreement and shall be based upon
actual fuel usage in Transporter's Hugoton Gathering System.
(4) Either party shall have the annual right to request
renegotiation of the gathering rates to be effective 2/1/10
and each February 1 thereafter. Such request shall be made in
writing and given to the other party not less than six months
prior to the date the renegotiated rate(s) would become
effective. If the parties are unable to mutually agree to
renegotiated rate(s), then this Agreement shall terminate
after 1/31/10.
(5) The Base Rate I shall be $0.13 per Dth from 1/31/95 to
1/31/97, $0.14 per Dth from 2/1/97 through 1/21/98, $0.145 per
Dth from 2/1/98 through 1/31/99, and $0.15 per Dth from 2/1/99
through 1/31/00. Effective 2/1/00 through 1/31/10, the Base
Rate I will be determined monthly, and shall be equal to 9% of
the index price for PEPL-Oklahoma published in the first issue
of Inside FERC's Gas Market Report for such month. If such
index price ceases to be published, then Shipper and
Transporter shall select a mutually agreeable substitute
generally recognized in the industry. In no event shall the
Base Rate I be less than $0.15 per Dth after 1/31/99.
Transporter's maximum obligation under Base Rates I and II
shall be 15,000 Mcf per day.
(6) Pursuant to the terms of the June 1, 1994 Letter Agreement
between the parties, an Incremental Facilities Usage Rate
("IFUR") of $0.06 per Dth shall apply in addition to the rates
set forth above. The IFUR will continue in effect until the
earlier of (i) 2/1/99 or (ii) the first day of the month
immediately following the month in which the aggregate revenue
attributable to the IFUR equals Transporter's actual costs of
the New Facilities, as defined in the Letter Agreement dated
June 1, 1994. If the actual costs of the New Facilities
exceed the aggregate of the IFUR charges paid and accrued
between 1/30/95 and 2/1/99, Shipper shall reimburse
Transporter for the difference in a lump sum payment, within
thirty days of Transporter's invoice. If any part of such
difference resulted from a production limitation caused by
Transporter's inability to meet pressure specifications set
forth in Exhibit "B", then that part of the payment will be
deferred for a period of time equal to the time period
Transporter interrupted delivery of Shipper's Gas. Shipper
shall have the right to audit Transporter's records to verify
the costs of the New Facilities.
(7) The Base Rate II shall be applicable to Shipper's Directly
Connected Gas (Exhibit "B", Schedule 3) and shall be $0.01 per
Dth for a three year period commencing with the first delivery
of gas from each new source. Thereafter, the Base Rate II
shall equal the Base Rate I then in effect and as it may
change from time to time. At no time however, shall the sum
of the Base Rate II and the IFUR be less than Transporter's
minimum tariff gathering rate. No fuel retention shall apply
for a three year period commencing with the first delivery of
gas from each new connection of Shipper's Directly Connected
Gas. Transporter's maximum obligation under Base Rates I and
II shall be 15,000 Mcf per day.
<PAGE>
Contract No. 42026000A
AMENDMENT
DATED: January 5, 1994
---------------
to
GAS GATHERING AGREEMENT - INTERRUPTIBLE
between
COLORADO INTERSTATE GAS COMPANY
and
MESA OPERATING CO.
ACTING ON BEHALF OF ITSELF AND AS AGENT
FOR HUGOTON CAPITAL LIMITED PARTNERSHIP
DATED: October 1, 1993
---------------
<PAGE>
AMENDMENT TO
GAS GATHERING AGREEMENT - INTERRUPTIBLE
THIS AMENDMENT, made and entered into as of this 5th day of January
1994, by and between COLORADO INTERSTATE GAS COMPANY, hereinafter referred
to as "Transporter", and MESA OPERATING CO., acting on behalf of itself and
as agent for Hugoton Capital Limited Partnership, hereinafter referred to
as "Shipper".
WHEREAS, Transporter and Mesa Operating Limited Partnership entered
into a Gas Gathering Agreement (Agreement) dated October 1, 1993,
providing for the gathering by Transporter of supplies of natural gas which
Shipper has acquired in the vicinity of Transporter's gathering system; and
WHEREAS, Mesa Operating Limited Partnership notified Transporter that
its name has changed to Mesa Operating Co., acting on behalf of itself and
as agent for Hugoton Capital Limited Partnership; and
WHEREAS, Transporter and Shipper desire to amend the Agreement to
document changes in the Gathering Rates and operating pressure commitments
in the Hugoton Field pursuant to Letter Agreements dated January 5, 1994
and June 1, 1994; and
WHEREAS, Transporter and Shipper desire to further amend the Agreement
pursuant to the Letter Agreement dated June 1, 1994 to add Satanta as a
Point of Delivery and to extend the primary term of the agreement to
January 31, 2010; and
WHEREAS, Transporter and Shipper desire to amend the Agreement further
to document changes in gas quality specifications and procedures to
determine uneconomic wells pursuant to the Letter Agreement dated June 1,
1994;
NOW, THEREFORE, in consideration of the premises and the mutual
covenants hereinafter contained, Transporter and Shipper agree to amend the
Agreement as follows:
1. Shipper notified Transporter of a name change from Mesa Operating
Limited Partnership to Mesa Operating Co., effective January 5, 1994. Mesa
Operating Co. shall be substituted for Mesa Operating Limited Partnership
wherever it occurs in this Agreement, effective January 5, 1994.
2. Effective January 5, 1994, Appendix "A" shall be deleted in its
entirety and the attached Appendix "A" shall be substituted therefore.
3. Effective January 5, 1994, Exhibit "B" shall be deleted in its
entirety and the attached Exhibit "B" shall be substituted therefore.
4. Effective June 10, 1994, Paragraph 2 of the Agreement shall be
deleted in its entirety and the following Paragraph 2 shall be substituted
therefore.
"2. Term of Agreement: Beginning: October 1, 1993
Ending: January 31, 2010
X Year to year thereafter, provided that the parties agree to
---
gathering rates to be in effect after January 31, 2010. See Appendix "A"
for additional information."
5. Effective June 10, 1994, Paragraph 4 of the Agreement shall be
deleted in its entirety and the following Paragraph 4 shall be substituted
therefore.
"4. This Agreement is subject to the rates contained in
Appendix "A" and to all of the terms of the attached General Terms and
Conditions - Interruptible Gathering (see Exhibit "A"), except as
adjusted as follows:
Article 8 - Quality Specifications
In addition to the gas quality specifications described in Article 8, the
following gas quality specifications shall apply to gas delivered to
Satanta. Transporter shall not process such gas prior to delivery.
Shipper shall retain all processing rights associated with Shipper's gas
delivered to the Satanta Point of Delivery. The parties acknowledge that
the Btu and hydrocarbon components of the gas delivered to Satanta from
time to time will vary subject to such commingled stream available from
Transporter. However, in the event such commingled stream contains more
than 350 parts per million of carbon dioxide by volume, more than four
parts per million of hydrogen sulfide by volume, or any mercury at the
inlet to the plant, the parties shall undertake the following in order:
(1) Shipper shall notify Transporter of any such non-
conformance with the above specifications. Shipper represents that these
quality specifications are the same as, and no more stringent than, the
quality requirements for any gas being delivered to Satanta.
(2) Shipper shall have the right, but not the obligation,
to treat the gas which is the source of the non-conformance at its sole
cost or to pay for treatment of such gas at a mutually agreeable point on
CIG's Hugoton Gathering System.
(3) If it is not economic for Shipper to treat such gas,
excluding the gas described in Exhibit "B", Schedule 3, then Transporter
shall have the right, but not the obligation, to remedy such non-
conformance at no cost to Shipper. In determining whether it is economic
to treat non-complying gas delivered hereunder, Shipper shall consider such
gas with all other gas being delivered to the Satanta Point of Delivery
which requires treatment for carbon dioxide and/or hydrogen sulfide and
provide similar economic evaluations for non-complying gas delivered
hereunder as are provided for any other such non-complying gas. Further,
any such economic evaluations shall also include the blending of such gas
delivered hereunder with all gas being delivered to the Satanta Point of
Delivery. In any event, Shipper shall be responsible for treating
Shipper's Directly-Connected Gas (Exhibit "B", Schedule 3) which shall
be excluded in determining whether or not treatment is economic.
(4) If Shipper does not determine that there is an economic
solution available for the non-complying gas (other than Shipper's
Directly-Connected Gas, Exhibit "B", Schedule 3) and Transporter does not
restore the gas quality to the standards set forth above, then Shipper may
terminate this Agreement, with no further obligations on the part of either
party, including, but not limited to, any costs described in Footnote 6 in
Appendix "A", but excluding payments by Shipper for services rendered prior
to such termination. If the commingled stream, not including Shipper's New
Gas and Shipper's Directly Connected Gas (Exhibit "B", Schedules 2 and 3),
to be delivered to the Satanta Point of Delivery by Transporter hereunder,
contains more than 0.5% of carbon dioxide by volume, Shipper shall also
have the right to terminate this Agreement with no further obligations on
the part of either party, including, but not limited to, any costs
described in Footnote 6, Appendix "A", but excluding payments by Shipper
for services rendered prior to such termination.
6. Effective June 10, 1994, Paragraph 9 of the Agreement shall be
deleted in its entirety and the following Paragraph 9 shall be substituted
therefore.
"9. Other Operating Provisions:
Uneconomic Wells and Installation of Compression
------------------------------------------------
If, for any prior twelve month period, providing gathering service
from a particular well to the delivery points hereunder has been uneconomic
to Transporter, then Transporter may request a volume increase commitment
or a renegotiation of the gathering rate for that particular well. For
purposes of this section, gathering services from a well to the delivery
points are uneconomic for a well if gathering revenues derived from the
Base Rate specified in Appendix "A" and received from production from that
particular well are less than 126% of Shipper's share of the direct cost of
operating the gathering facilities, calibrating, maintaining and reading
the wellhead meters, treating by Transporter if any, to conform to quality
specifications of Article 8, and operating and maintaining compression to
effect deliveries hereunder for each well in question. Transporter shall
not be required to install any additional facilities for that well unless
Shipper agrees at that time that Transporter can include the cost of such
additional facilities in the direct cost of gathering for such well for the
purpose of determining whether providing gathering service for a particular
well has been uneconomic for Transporter. Direct cost(s) are expenditures
for materials and services actually used on the gathering system or at the
gathering system level for the direct benefit of the gathering system and
include expenditures for operating field lines, operating field compressor
stations, field compressor station fuel and power provided by Transporter,
operating field measuring and regulating station equipment, rent of items
located on the gathering system, maintenance of field structures and
improvements, maintenance of field lines, maintenance of field compressor
station equipment, maintenance of field measuring and regulating station
equipment, and First Level Supervision. First Level Supervision includes
those employees actually located in the field whose primary function is the
direct supervision of other employees and/or contract labor directly
located on the gathering system in an operating capacity. All other costs,
including supervisors and managers above First Level Supervision are not
included in Direct Costs. Shipper shall have the right to audit
Transporter's calculations and records which support Transporter's claim
that providing gathering service to a particular Shipper well is
uneconomic. If agreement on a volume increase or a new gathering rate for
such well cannot be reached, Shipper may elect to contract operate the
measurement facilities and wellhead compression, if any, for such Shipper
well or wells, provided that arrangements shall be made to accommodate
other parties' gas and that Shipper shall be responsible only for operating
the wellhead gathering facilities, calibrating, reading and maintaining the
wellhead meters and allocating the gas delivered to a central delivery
meter among all Shipper wells connected to the lateral. If multiple
Shipper wells connected to a lateral are determined to be uneconomic,
Transporter, at its sole cost, will install metering facilities for custody
transfer measurement at a location downstream of the Shipper wells
determined to be uneconomic. Transporter will continue to maintain the
gathering lines and wellhead gathering facilities. Shipper will have the
right to install central compression on such lateral. If agreement on a
volume increase or new gathering rate cannot be reached and Shipper elects
not to contract operate the affected measurement facilities and wellhead
compression, if any, Transporter may discontinue gathering service for such
well and the Agreement will be terminated for such well.
Gathering System Capacity
-------------------------
Shipper's gas will be received into Transporter's Hugoton Gathering
System on an interruptible basis and Transporter shall notify Shipper in
the event of a reduction in available capacity to the Satanta Point of
Delivery from any well. As to Shipper's gas nominated, scheduled and
received into Transporter's Hugoton Gathering System for delivery to the
Satanta Point of Delivery, Transporter shall deliver and Shipper shall
receive Shipper's gas less fuel (as set forth in Appendix "A") at the
Satanta Point of Delivery, subject only to events of force majeure as set
forth in Article 11. Shipper shall have the continuing option to convert
this Agreement to a firm gathering agreement to the Satanta Point of
Delivery on a well by well basis, as needed. Any such conversion shall be
effective until the following February 1 and continue in effect thereafter
unless terminated effective on a February 1 by Shipper's thirty day prior
written notice to Transporter. Firm gathering shall be at Transporter's
maximum rates as such rates may change from time to time. If Transporter
fails to notify Shipper of a reduction in available capacity and
Transporter cannot provide sufficient gathering capacity to permit Shipper
to convert to firm gathering service for a particular well, then Shipper
may terminate this Agreement as to that well. Shipper shall have the right
to convert back to interruptible service at each February 1; provided
however, if Shipper converts back to interruptible service, such service
will be interruptible for the remaining term of this Agreement.
Split Connect Provision
-----------------------
Shipper, as to its interest, its affiliates' interest and its
successors' interest in any well producing Shipper's Gas, hereby agrees for
the term hereunder not to split - connect any of the Shipper wells
currently or hereafter connected to Transporter's Hugoton Gathering System.
Additional Provisions
---------------------
In the event of any conflict between the terms and provisions of this
Agreement and the Letter Agreements between Shipper and Transporter dated
January 5 and June 1, 1994, or the letter from Transporter to Shipper dated
January 17, 1994, such Letter Agreements and letter shall control."
7. Effective January 5, 1994, Paragraph 7 of the Agreement shall be
deleted in its entirety and the following Paragraph 7 shall be substituted
therefore.
"7. Notices: Transporter: Colorado Interstate Gas Company
P.O. Box 1087
Colorado Springs, CO 80944
Attention: Gathering Department
Gathering Department Fax: (719) 520-
4449
Volume Management Fax: (719) 520-
4449
Shipper: Mesa Operating Co.
5205 N. O'Conner Blvd., Suite 1400
Irving TX 75039-3746
Attention: Steve Tennison
Fax: (214) 444-4394"
This Amendment shall be effective as of the dates set forth in
Paragraphs 1 through 7 above, and except as herein amended, the Agreement
shall in all respects remain in full force and effect.
IN WITNESS WHEREOF, the Parties have executed this Amendment as of the
9th day of October, 1995.
- --- -------
COLORADO INTERSTATE GAS COMPANY
(Transporter)
By /s/ S. W. Zuckweiler
----------------------------
S.W. Zuckweiler
Vice President
MESA OPERATING CO. ACTING ON BEHALF
OF ITSELF AND AS AGENT FOR
HUGOTON CAPITAL LIMITED PARTNERSHIP
(Shipper)
By /S/ Steven R. Tennison
-------------------------------
Steven R. Tennison
-------------------------------
(Print or type name)
Attorney-in-Fact
-------------------------------
(Print or type title)
<PAGE>
Contract No. 11085
(MESA LOGO)
January 5, 1994
Mr. S. W. Zuckweiler
Colorado Interstate Gas Company
P. O. Box 1087
Colorado Springs, CO 80944
Gentlemen:
Since May 1993, production from certain wells owned by Mesa Operating
Limited Partnership (MESA) has been curtailed as a result of an increase in
the operating pressure of the Hugoton Gathering System owned by Colorado
Interstate Gas Company (CIG). After numerous discussions, CIG and MESA
have determined the installation of four compressors will allow MESA to
resume normal production levels from the wells connected to the six
laterals listed in Attachment A (CIG Laterals). Both MESA and CIG agree to
proceed with the installation and operation of such compressors pursuant to
the following terms and conditions.
1. CIG, at its sole cost, shall provide inlet and outlet connections
between each of the six CIG Laterals listed in Attachment A, the
four compressors to be installed by MESA at its sole cost, and
CIG's Hugoton Gathering System downstream of MESA's compressor
units. Such compressors will be located at sites mutually agreed
to by MESA and CIG.
2. CIG, at its sole cost, shall connect to the nearest CIG Lateral
the Winger C-4, Winger C-2, Winger C-1 and Winger 10-33. If the
gathering revenue received from said wells in the period beginning
with completion of the new connections until January 31, 1996, is
less than the cost of such connections, then MESA shall reimburse
CIG for the difference within 10 days of CIG's invoice date.
3. As soon as possible after signing this agreement, MESA shall
furnish, own, maintain and operate at its own cost four compressor
units at mutually agreeable locations. CIG's delivery obligation
under the gathering agreement shall be reduced by the quantity of
fuel gas used in the operation of said compressors. In addition
to its gas, MESA shall compress the gas produced by third parties
from the wells connected to the CIG Laterals as of the date of
this agreement. Further, the volumes MESA shall be required to
compress for third parties shall be limited to the volume levels
produced for such third parties during the last month prior to
May, 1993, in which full production occurred. CIG shall reimburse
MESA in-kind for the actual fuel gas attributed to the compression
of such third parties' volumes.
4. CIG shall use its best efforts to operate its Hugoton Gathering
System at the CIG Lateral interconnections at pressures not in
excess of 125 psig, but in no event shall the pressures at CIG
Lateral interconnections exceed 137 psig.
5. CIG agrees to reduce by $0.013 per MMBtu the gathering fee charged
pursuant to the present gathering agreement for gas gathering for
MESA's account through the CIG laterals.
6. This letter agreement shall remain in effect until MESA elects to
remove the compressors installed pursuant to Item 3 above,
provided, however, if MESA removes the compressors prior to
January 31, 1996, and the gathering revenues attributed to the
wells on the CIG Laterals, less revenues from the wells identified
in Paragraph 2, are less than the costs incurred by CIG under
Paragraph 1, then MESA shall reimburse CIG for the difference
within 10 days of CIG's invoice date.
Nothing in this letter agreement shall be deemed an admission of law or
fact by either party. If the above terms and conditions are acceptable to
CIG, please execute a copy of this letter and return it to us. We look
forward to beginning work on this project.
Sincerely,
/s/ S. Leonard Hruzek, Jr.
S. Leonard Hruzek, Jr.
SLH/kkh
ACCEPTED AND AGREED TO:
COLORADO INTERSTATE GAS COMPANY
By: /s/ S.W. Zuckweiler
---------------------
S.W. Zuckweiler
Vice President
Date: August 17, 1994
---------------
<PAGE>
ATTACHMENT "A"
Laterals in Lakin Gathering System
1. Lateral west of the Interconnect with F54-8" in 33-27S-40W
2. Lateral east of the Interconnect with F54-8" in 33-27S-40W
3. Lateral west of the Interconnect with F54-8" in 28-27S-40W
4. Lateral east of the Interconnect with F54-8" in 28-27S-40W
5. Lateral east of the Interconnect with F9-10" in 21-27S-40W
6. Lateral east of the Interconnect with F9-10" in 15-27S-40W
<PAGE>
Dennis E. Fagerstone
vice president-exploration & production
(MESA LOGO)
June 1, 1994
Mr. Steve W. Zuckweiler
Colorado Interstate Gas Company
P. O. Box 1087
Colorado Springs CO. 80944
Re: Connection of CIG Facilities
To Mesa's Satanta Plant; Terms,
Rates of Gathering Service
Dear Mr. Zuckweiler:
This letter will set forth the agreement between Colorado Interstate Gas
Company ("CIG") and Mesa Operating Co. ("MESA"), acting on behalf of itself
and as agent for Hugoton Capital Limited Partnership ("HCLP"), regarding
the connection of CIG's facilities to MESA's Satanta Gas Processing Plant
and the terms and conditions which will govern the gathering of gas by CIG
for MESA in the area of CIG's Hugoton Gathering System in southwest Kansas.
Accordingly, for and in consideration of the premises and mutual covenants
herein contained, CIG and MESA hereby agree as follows:
1. CIG will, at its sole cost, construct, own and operate facilities for
delivery of up to 15 MMcf/d from CIG's Hugoton Gathering System Area
to MESA's Satanta Plant at 100 psig. CIG's new facilities shall
include approximately 5.5 miles of pipeline between CIG's existing F1-
12" gathering line and the inlet to MESA's Satanta Plant, electronic
measurement at CIG's Delivery Point to the Satanta Plant inlet, and
initial modifications required to existing CIG gathering compressors
HFC #1 and HFC #6 to facilitate the delivery of up to 15 MMcf/d from
CIG's Hugoton Gathering System Area to Mesa's Satanta Plant at 100
psig ("New Facilities"). CIG shall complete construction of the New
Facilities within eight months of execution of this Agreement by CIG
and MESA.
2. MESA shall install, maintain and operate its facilities to provide for
a constant pressure of 100 psig at CIG's Delivery Point to the Satanta
Plant inlet.
3. Gas gathered by CIG to the Satanta Plant shall be limited to (i)
MESA's existing and future gas production from wells now connected to
CIG's Hugoton Gathering System ("MESA-Owned Gas"), (ii) third-party
gas marketed by MESA from existing MESA-operated wells now connected
to CIG's Hugoton Gathering System ("MESA-Operated Gas"), (iii) gas
which MESA may deliver from new sources (other than those specified in
(iv) of this sentence which MESA connects or causes to be connected to
CIG's Hugoton Gathering System ("MESA's New Gas") and (iv) gas which
MESA may deliver through MESA's new connections made directly into
CIG's 5.5 mile pipeline between CIG's F1-12" gathering line and the
inlet to the Satanta Plant ("MESA's Directly-Connected Gas");
hereinafter collectively referred to as "MESA's Gas." CIG shall not
process such gas prior to delivery. MESA shall retain all processing
rights associated with MESA's Gas. MESA's Gas will be commingled with
other gas in CIG's Hugoton Gathering System prior to delivery to the
Satanta Plant. The parties acknowledge that the Btu and hydrocarbon
components of the gas delivered from time to time will vary subject to
such commingled stream available from CIG at the inlet of the Satanta
Plant. CIG's delivery obligation shall be limited to that quantity
of Dths received by CIG from MESA, less gathering fuel. However, in
the event such commingled stream contains more than 350 parts per
million of carbon dioxide by volume, more than four parts per million
of hydrogen sulphide by volume or any mercury at the inlet to MESA's
Satanta Plant, the parties shall undertake the following in order:
(1) MESA shall notify CIG of any such non-conformance with the above
specifications. MESA represents that these quality specifications
are the same as, and no more stringent than, the quality requirements
for any non-Mesa Gas being delivered to the Satanta Plant. (2) MESA
shall have the right but not the obligation to treat the gas which is
the source of non-conformance at its sole cost or to pay for treatment
of such gas at a mutually agreeable point on CIG's Hugoton Gathering
System. (3) If it is not economic for MESA to treat such gas, except
MESA's Directly-Connected Gas, then CIG shall have the right but not
the obligation to remedy such non-conformance at no cost to MESA. In
determining whether there is an economic solution to treat non-
complying gas being delivered by CIG hereunder, MESA shall consider
such CIG-delivered gas with all volumes being delivered to Satanta
which require treatment for carbon dioxide and/or hydrogen sulphide
and provide similar economic evaluations for CIG-delivered non-
complying gas as are provided for any other such non-complying gas.
Further, any such economic evaluation shall also include the blending
of such CIG-delivered gas with all gas being delivered to Satanta. In
any event, MESA shall be responsible for treating MESA's Directly-
Connected Gas which shall be excluded in determining whether or not
treatment is economic. (4) If the parties cannot agree that there is
an economic solution available for the non-complying gas (other than
MESA's Directly-Connected Gas) and/or CIG does not restore the gas
quality to standards set forth above, then MESA may terminate this
Agreement, with no further obligations on the part of either party,
including, but not limited to, any costs under Paragraphs 12 and 13
below, but excluding payments by MESA for services rendered prior to
such terminations. If the commingled stream, not including MESA's New
Gas and MESA's Directly-Connected Gas, to be delivered to the Satanta
Plant by CIG hereunder, contains more than 0.5% of carbon dioxide by
volume, MESA also shall have the right to terminate this agreement
with no further obligations on the part of either party hereunder,
including, but not limited to, any costs under Paragraphs 12 and 13
below, but excluding payments by MESA for services rendered prior to
such termination.
4. MESA's gas will be received into the CIG Hugoton Gathering System on
an interruptible basis and CIG shall notify MESA in the event of a
reduction in available capacity to the Satanta Plant from any well.
Once MESA's Gas is nominated, scheduled and received into the CIG
Hugoton Gathering System, CIG shall deliver and MESA shall receive
MESA's Gas less Fuel (as hereinafter defined) at the inlet of the
Satanta Plant, subject only to events of force majeure as set forth in
the gathering agreement between the parties. MESA shall have the
continuing option to convert the interruptible gathering agreement to
a firm gathering agreement to the Satanta Plant on a well by well
basis, as needed for the remainder of the Contract Year and each
Contract Year thereafter, at CIG's maximum rates for firm gathering as
such rates may change from time to time. If CIG fails to notify MESA
of a reduction in available capacity and CIG cannot provide sufficient
gathering capacity to permit MESA to convert to firm gathering service
for a particular well, then MESA may terminate this agreement as to
that well. MESA shall have the right to convert back to
interruptible service at the end of each Contract Year; provided
however, if MESA converts back to interruptible service, such service
will be interruptible for the remaining term of the agreement.
5. Subject to Paragraphs 3 and 4 above, the term of the rates and the
other conditions of this agreement shall be 15 Contract Years and year
to year thereafter. Thereafter, either party shall have the annual
right to request renegotiation of the gathering rates to be effective
after the first 15 Contract Years. Such request shall be made in
writing and given to the other party not less than six months prior to
the start of the Contract Year in which such renegotiated rates would
become effective. If the parties are unable to mutually agree to a
renegotiated rate, then this agreement shall terminate.
6. The gathering rates hereunder shall consist of a Base Rate I or a Base
Rate II, whichever is applicable, and an Incremental Facilities Usage
Rate as defined in Paragraph 12 below ("IFUR"). The gathering charges
to be paid by MESA hereunder shall be calculated by applying the
applicable Base Rate and the IFUR to MESA's Gas received into CIG's
Hugoton Gathering System. In addition to the above charges, CIG shall
retain quantities for Fuel, which is defined as a percentage of
MESA's Gas received for gathering by CIG (the Fuel Percentage), except
that the Fuel Percentage will not be applied to MESA's Directly-
Connected Gas for a three-year period commencing with the first
delivery of gas from each new connection to CIG's 5.5-mile pipeline.
The Fuel Percentage (currently 3%) shall be adjusted from time to time
throughout the term of the agreement and shall be based upon actual
fuel usage in CIG's Hugoton Gathering System.
7. Effective in the first two Contract Years, the initial Base Rate I
shall be applicable for gathering MESA-Owned Gas, MESA-Operated Gas
and MESA's New Gas to the Satanta Plant on an interruptible basis and
shall be $.13 per Dth. The first Contract Year shall commence upon
initial delivery of gas by CIG to the Satanta Plant and shall continue
until the first day of the month following the anniversary of
initial delivery. Thereafter, each Contract Year shall consist of 12
months commencing on the first day of the month following each
anniversary o initial delivery. The Base Rate I shall escalate to
$.14 per Dth in the third Contract Year, $.145 per Dth in the fourth
Contract Year and $.15 per Dth in the fifth Contract Year. Thereafter,
the Base Rate I each month shall be equal to 9% of the index price for
PEPL-Oklahoma published in the first issue of Inside FERC's Gas Market
Report for such month. If such index price ceases to be published,
then MESA and CIG shall select a mutually agreeable substitute
generally recognized in the industry. In no event, however, shall the
Base Rate I be less than $0.15 per Dth for the fifth Contract Year and
thereafter. The rates for service hereunder shall apply only to
gathering services in CIG's Hugoton Gathering System Area.
8. Gathering rates to the Lakin Master Meter shall be the Base Rate I
plus $0.025 per Dth plus the IFUR. In addition, CIG shall retain
quantities for Fuel as defined in Paragraph 6 above.
9. The Base Rate II shall be applicable for MESA's Directly-Connected Gas
and shall be $0.01 per Dth for a three-year period commencing with the
first delivery of gas from each new source. Thereafter, the Base Rate
II for MESA's Directly-Connected Gas shall equal the Base Rate I then
in effect and as it may change from time to time. At no time however,
shall the sum of the Base Rate II and the IFUR be less than CIG's
minimum tariff gathering rate. MESA shall be responsible for and
shall pay all costs associated with connecting MESA's Directly-
Connected Gas to CIG's 5.5-mile pipeline.
10. If, for any prior twelve-month period, providing gathering service
from a particular well to the delivery points hereunder has been
uneconomic to CIG, then CIG may request a volume increase commitment
or a renegotiation of the gathering rate for that particular well.
For purposes of this section, gathering services from a well to the
delivery points are uneconomic for a well if gathering revenues
derived from the Base Rate specified herein and received from
production from that particular well are less than 126% of MESA's
share of the direct cost of operating the gathering facilities,
calibrating, maintaining and reading the wellhead meters, treating by
CIG if any, to conform MESA's Gas to the specifications of Paragraph
3, and operating and maintaining compression to effect deliveries
hereunder for each well in question. CIG shall not be required to
install any additional facilities for that well unless MESA agrees at
that time that CIG can include the cost of such additional facilities
in
the direct cost of gathering for such well for the purpose of
determining whether providing gathering service for a particular well
has been uneconomic for CIG. Direct cost(s) are expenditures for
materials and services actually used on the gathering system or at the
gathering system level for the direct benefit of the gathering system
and include expenditures for operating field lines, operating fuel
compressor stations, field compressor station fuel and power provided
by CIG, operating field measuring and regulating station equipment,
rent of items located on the gathering system, maintenance of field
structures and improvements, maintenance of field lines, maintenance
of field measuring and regulating station equipment, and First Level
Supervision. First Level Supervision includes those employees
actually located in the field whose primary function is the direct
supervision of other employees and/or contract labor directly located
on the gathering system in an operating capacity. All other costs,
including supervisors and managers above First Level Supervision are
not included in Direct Costs. MESA shall have the right to audit
CIG's calculations and records which support CIG's claim that
providing gathering service to a particular well is uneconomic. If
agreement on a volume increase or a new gathering rate for such well
cannot be reached, MESA may elect to contract operate the measurement
facilities and wellhead compression, if any, for such MESA well or
wells, provided that arrangements shall be made to accommodate other
parties' gas and that MESA shall be responsible only for operating the
wellhead gathering facilities, calibrating, reading and maintaining
the wellhead meters and allocating the gas delivered to a central
delivery meter among all MESA wells connected to the lateral. If
multiple MESA wells connected to a lateral are determined to be
uneconomic, CIG, at its sole cost, will install metering facilities
for custody transfer measurement at a location downstream of the MESA
wells determined to be uneconomic. CIG will continue to maintain the
gathering lines and wellhead gathering facilities. MESA will have the
right to install central compression on such lateral. If agreement on
a volume increase or new gathering rate cannot be reached and MESA
elects not to contract operate the affected measurement facilities and
wellhead compression, if any, CIG may discontinue gathering service
for such well and the agreement will be terminated for such well.
11. As soon as practicable but no later than July 1, 1994, MESA shall
commence operation of CIG's meters and gathering laterals which serve
MESA's wells upstream of CIG's F9-12" gathering pipeline in Section
28, T26S, R39W, Hamilton County, Kansas, provided that arrangements
shall be made to accommodate other parties' gas and that MESA shall be
responsible only for operating the wellhead gathering facilities on
MESA's wells, calibrating, reading and maintaining the wellhead meters
for MESA's wells and allocating the gas delivered to a central
delivery meter among all MESA wells connected to the lateral. MESA
shall furnish CIG with monthly measurement information on each such
well. CIG, at its sole cost, will install, if suitable existing
central measurement is not available, and operate the central metering
facilities for custody transfer measurement and will continue to
maintain the gathering lines and wellhead gathering facilities. MESA
will have the right to install central compression at the connections
of CIG's laterals to CIG's F54-8" in Section 4, T28S, R40W, Stanton
County, Kansas, and CIG"s F51-8" in Section 20, 28 or 29, T26S, R39W,
Hamilton County, Kansas, provided that arrangements shall be made to
accommodate other parties' gas and that MESA's compression does not
cause CIG's gathering system pressures to exceed the limits set forth
in Paragraph 14. Notwithstanding the above, MESA shall have the right
to deliver a minimum of 7.5 MMCF per day through such compressors
without regard to such pressure limits set forth in Paragraph 14, and
CIG shall continue to be obligated to operate its gathering system at
pressure which do not exceed the limits set forth in Paragraph 14. CIG
shall reimburse MESA in-kind for actual fuel attributed to this
compression by MESA of all gas compressed on such laterals other than
MESA's Gas.
12. In addition to the Base Rate, an Incremental Facilities Usage Rate
("IFUR") of $.06 per Dth shall apply to all of MESA's Gas. The IFUR
shall be in effect commencing on the date of initial delivery of gas
by CIG to the Satanta Plant. The IFUR shall continue in effect until
the earlier of (i) the first day of the fifth Contract Year or (ii)
the first day of the month immediately following the month in which
the aggregate revenue attributable to the IFUR equals CIG's actual
costs (including but not limited to materials, contract costs, rights-
of-way, permits, engineering, supervision and allowance for funds used
during construction) of the New Facilities.
13. To the extent that the actual costs of the New Facilities, as defined
in Paragraph 12, exceed the aggregate of the IFUR charges paid and
accrued between initial delivery and the first day of the fifth
Contract Year, MESA shall reimburse CIG for the difference in a lump
sum payment within 30 days of CIG's invoice. If any part of such
difference resulted from a production limitation caused by CIG's
inability to meet the pressure specifications set forth in Paragraph
14 below, then that part of the payment will be deferred for a period
of time equal to the time period CIG interrupted delivery of MESA's
gas. MESA shall have the right to audit CIG's records to verify costs
of the New Facilities.
14. Operating Pressure Commitment
A. CIG shall use its good faith efforts to operate its Hugoton
Gathering System at the CIG lateral interconnections in Stanton
County, Kansas which are listed below, at pressures not in excess
of 125 psig, but in no event shall the pressure exceed 137 psig.
(a) Lateral west of the interconnect with F54-8" in Section 33,
T27S, R40W.
(b) Lateral east of the interconnect with F54-8" in Section 33,
T27S, R40W.
(c) Lateral west of the interconnect with F54-8" in Section 28,
T27S, R40W.
(d) Lateral east of the interconnect with F54-8" in Section 28,
T27S, R40W.
(e) Lateral east of the interconnect with F9-10" in Section 21,
T27S, R40W.
(f) Lateral east of the interconnect with F9-10" in Section 15,
T27S, R40W.
B. CIG shall maintain a monthly average pressure not to exceed 85
psig at the interconnection point of CIG's F2617-4", F2607-4",
F2606-4" and F28-8" gathering lines and CIG's F1L-12" gathering
trunkline and CIG's F50-4" gathering line at the interconnect
point with CIG's F1-16" gathering trunkline. Said gathering
lines are used to gather MESA-Owned Gas from producing wells
located in Sections 29, 32 and 33, T28S, R34W; Sections 27, 33,
and 34, T27S, R33W; Sections 6 and 9, T29S, R33W, and Sections 1,2
and 4, T29S, R34W. CIG shall install at its sole cost the
necessary pressure measuring equipment at such points and shall
grant MESA access to the site and equipment so that MESA can
monitor pressure.
C. In the event that the pressures at one or more of the interconnect
points described in A above are exceeded any time, or in B above
are exceeded for three consecutive months, MESA shall provide
written notification to CIG of such actual pressures. Upon
verification and provided that MESA's installation of additional
compression is in conformance with Paragraph 11, CIG, as soon as
practicable but not more than 120 days after such notification
by MESA, excluding any days of delay in obtaining rights-of-way,
shall install, solely at its cost, compression, loopline, or any
other facilities necessary to achieve the required pressure at
that location. In the event that CIG encounters a delay or is
prevented from obtaining rights-of-way, MESA may obtain such
rights-of-way satisfactory to CIG, and shall assign same to CIG,
and CIG shall reimburse MESA for the cost of such rights-of-way.
D. Except as provided above, MESA shall deliver all other MESA's Gas
to CIG at sufficient pressures to effect delivery.
15. MESA, as to its interest, its affiliates' interest and its successors'
interest in any well producing MESA's Gas, shall agree for the term
hereunder not to split-connect any of the MESA wells currently or
hereunder connected to CIG's Hugoton Gathering System.
16. MESA shall have the right to deliver "B" Contract fuel gas make up to
CIG at the outlet of the Satanta Plant, provided that (i) MESA shall
contract for, administer and pay any and all costs associated with
third-party transportation of such gas to CIG's transmission system;
or (ii) in the alternative, and at CIG's discretion, such gas may be
delivered to a third-party pipeline for CIG's Shippers' accounts
provided there is no incremental cost to CIG or to its Shippers
associated with such deliveries.
17. This Agreement is subject to the force majeure provisions of the Gas
Gathering Agreement-Interruptible dated October 1, 1993, between CIG
and MESA. This Agreement, when executed by both parties, shall be
deemed to amend that certain agreement dated October 1, 1993, to
reflect the terms and conditions set froth herein. To the extent
there is any conflict between this Agreement and the Agreement dated
October 1, 1993, this Agreement shall govern.
18. All provisions of this Agreement shall apply only to gathering
services in CIG's Hugoton Gathering System Area.
If the foregoing is in accordance with your understanding, please so
indicate by signing in the space provided below and returning an
original to the undersigned.
Very truly yours,
MESA OPERATING CO.
ACTING ON BEHALF OF ITSELF AND AS AGENT
FOR HUGOTON CAPITAL LIMITED PARTNERSHIP
By: /s/ Dennis E. Fagerstone
-------------------------------------
Dennis E. Fagerstone
Vice President Exploration/Production
ACCEPTED AND AGREED TO
THIS 10th DAY OF JUNE, 1994.
---- ----
COLORADO INTERSTATE GAS COMPANY
By /s/ Steven W. Zuckweiler
-----------------------------
Steven W. Zuckweiler
Vice President
<PAGE>
Agreement No.: 42026000-
49023
AMENDMENT
DATED: March 1, 1996
to
GAS GATHERING AGREEMENT-INTERRUPTIBLE
between
COLORADO INTERSTATE GAS COMPANY
and
MESA OPERATING CO.
ACTING ON BEHALF OF ITSELF AND AS AGENT ON
BEHALF OF HUGOTON CAPITAL LIMITED PARTNERSHIP
DATED: October 1, 1993
<PAGE>
AMENDMENT TO
GAS GATHERING AGREEMENT-INTERRUPTIBLE
THIS AMENDMENT, entered into as of this 1st day of March, 1996, by and
between COLORADO INTERSTATE GAS COMPANY, herein called "Transporter," and
MESA OPERATING CO. acting on behalf of itself and as agent on behalf of
Hugoton Capital Limited Partnership hereinafter called "Shipper".
WHEREAS, Transporter and Shipper entered into a Gas Gathering
Agreement (Agreement) dated October 1, 1993, which provides for the
gathering by Transporter and Shipper; and
WHEREAS, Transporter and Shipper desire to revise the Imbalance
provisions of Article 2 of the General Terms and Conditions:
----------------------------
NOW, THEREFORE, for and in consideration of the premises and the
mutual covenants hereinafter contained, Transporter and Shipper agree that
effective March 1, 1996, Article 2 of the General Terms and Conditions
----------------------------
shall be amended by substituting the following Section 2.3 for Sections 2.3
and 2.4:
"2.3 Definitions and Resolution of Imbalances.
--------------------------------------------
(a) Definitions.
(i) "Imbalance." For the purposes of this Article,
"Imbalance" shall mean the difference each Month between the Dth received
hereunder by Shipper or Shipper's designee at the Point(s) of Delivery, and
the Dth received hereunder by Transporter for Shipper's account at the
Point(s) of Receipt upstream of the corresponding Point(s) of Delivery as
those Receipt Quantities are adjusted for Fuel Reimbursement. The
Imbalance shall be determined for each set of corresponding Point(s) of
Receipt and Delivery (in each gathering system) under the Agreement.
(ii) "Imbalance Percentage." For purposes of this Article,
"Imbalance Percentage" for each gathering system under this Agreement shall
be calculated by dividing the Imbalance in Dth in a gathering system in a
Month by the total Dth received in that gathering system in that month and
multiplying the quotient by 100. The Imbalance Percentage shall be
calculated separately for each set of corresponding quotient by 100. The
Imbalance Percentage shall be calculated separately for each set of
corresponding Point(s) of Receipt and Delivery (in each gathering system)
under the Agreement.
(b) Resolution of Imbalances. Each Month and separately for each
gathering system, the party owing an Imbalance to the other party shall
reduce the Imbalance to zero by making a payment to the other party. The
Imbalance payment shall be calculated by multiplying the Imbalance in Dth
by the applicable CIG Gathering Cashout price. The Denver South Average
CIG Gathering Cashout Price shall be used in computations for Southern
Gathering Systems (CIG systems in Kansas, Oklahoma, Colorado and Texas),
and the Denver North CIG Gathering Cashout Price shall be used for Northern
Gathering Systems (CIG systems in Wyoming and Utah). The Denver South
Price shall be the simple average of prices for ANR Oklahoma, NGPL
Oklahoma, NNG Oklahoma and PEPL Oklahoma published in Inside FERC's Gas
Market Report as the final monthly index price for the Month in which the
imbalance occurred. The Denver North Price shall be the CIG Rocky
Mountains price so published. In the event that the Imbalance Percentage
is greater than 7.5% in a Month, then the payment calculated as above
shall be increased by 10% as to payments owed Transporter by Shipper and
decreased by 10% as to payments owed Shipper by Transporter. Imbalance
payments so calculated and adjusted hereunder for each system shall be
aggregated each Month to determine the net Imbalance payment to be paid by
one party to the other. The aggregation of Imbalance payments and the net
Imbalance payment shall be reported on an attachment to the monthly
Imbalance statement. The net Imbalance payment shall be due within 10 days
of the date of the statement."
IN WITNESS WHEREOF, the Parties hereto have executed this Agreement on
March 1, 1996.
COLORADO INTERSTATE GAS COMPANY
(Transporter)
By: /s/ S. W. Zuckweiler
----------------------------
S. W. Zuckweiler
Vice President
MESA OPERATING CO. ACTING ON
BEHALF OF ITSELF AND AS
AGENT ON BEHALF OF HUGOTON
ATTEST: CAPITAL LIMITED PARTNERSHIP
(Shipper)
By /s/ Ora Broomfield By: /s/ Steven R. Tennison
------------------------- ----------------------------
Title: Associate Marketing Rep.
Steven R. Tennison
----------------------------
(Print or type name)
Attorney-in-Fact
----------------------------
(Print or type title)
GAS SUPPLY AGREEMENT
This Gas Supply Agreement (the "Agreement"), made and entered into
this 11th day of May, 1994 (the "Effective Date"), by and between MESA
OPERATING CO., a Delaware corporation, as successor to MESA OPERATING
LIMITED PARTNERSHIP, acting on behalf of and as agent for HUGOTON CAPITAL
LIMITED PARTNERSHIP, a Delaware limited partnership ("Buyer"), and WILLIAMS
GAS MARKETING COMPANY ("Seller"), sometimes referred to collectively as the
"Parties" or singularly as a "Party".
RECITALS
WHEREAS, Buyer and WILLIAMS NATURAL GAS COMPANY and its assignee(s)
(collectively "WNG") are parties to that certain Gas Purchase Agreement
dated December 1, 1989, as amended (the "Base Contract"), whereby Buyer has
contracted to sell specified quantities of natural gas to WNG;
WHEREAS, Buyer desires to purchase from Seller any and all gas
necessary to fully satisfy its obligation to sell and deliver natural gas
to WNG under the Base Contract;
WHEREAS, Seller desires to sell the natural gas necessary for Buyer to
meet its sales obligations to WNG under the Base Contract; and
WHEREAS, as an inducement to Buyer to enter into this Agreement,
Seller's parent corporation, Williams Field Services Group, Inc., is
providing for the benefit of Buyer its written guarantee (the "Gas Supply
Guarantee") of Seller's performance and financial obligations hereunder.
NOW THEREFORE, in consideration of the foregoing premises and the
mutual promises, agreements and covenants herein set forth, Buyer and
Seller agree as follows:
ARTICLE I.
DEFINITIONS
1. The provisions of ARTICLE II of the Base Contract shall apply
mutatis mutandis to this Agreement such that, unless otherwise specifically
indicated herein or as required to differentiate between the role of Buyer
as party-seller under the Base Contract and its role as purchaser of Gas"
hereunder, the words and terms defined in the Base Contract shall have the
same meaning in this Agreement. For all purposes of this Agreement, the
term "Business Day" shall mean any Day other than a Saturday, a Sunday, or
a state or federal bank holiday in Dallas, Texas.
ARTICLE II.
TERM
1. This Agreement shall become effective on the Effective Date and
shall remain in full force and effect for a term coterminous with that of
the Base Contract, and thereafter for so long as any right or obligation
thereunder remains in effect.
ARTICLE III.
QUANTITY
1. As required for Buyer to fully perform the Base Contract, Seller
shall sell and deliver and Buyer shall purchase and receive on each Day
throughout the term of this Agreement, and on the same basis and at the
required final delivery point(s) provided in the Base Contract, that
quantity of Gas in MMBTUs which is equal to the quantity of Gas in MMBTUs
which WNG calls for delivery at that same final delivery point(s) on the
same Day of the same Month under the Base Contract ("Daily Quantity").
Notwithstanding any other provisions to the contrary in this Agreement,
Seller shall have no obligation to sell and deliver and Buyer shall have no
obligation to purchase and accept the Daily Quantity unless and to the
extent WNG calls for deliveries under the Base Contract. In consideration
for Seller's agreement to sell and deliver Gas, subject to the terms of
this Agreement, Buyer agrees to pay Seller Two Million Three Hundred
Thousand Dollars ($2,300,000.00) within ten (10) Business Days from the
date of final execution of this Agreement by both Parties.
ARTICLE IV.
PRICE
1. The price to be paid to Seller by Buyer for the Daily Quantity
hereunder shall be identical to the price in effect, from time to time,
under the Base Contract and paid to Buyer by WNG pursuant to the Base
Contract. In the event of a price adjustment under the Base Contract
(including retroactive adjustments arising from the resolution of any
dispute between Buyer and WNG regarding the proper price payable under the
Base Contract), the price hereunder shall be adjusted accordingly and
additional payments, or refunds, as appropriate, shall be made by the
Parties for prior deliveries of Gas hereunder in order that the amounts
paid by Buyer and received by Seller hereunder equal the amounts paid by
WNG and received by Buyer under the Base Contract.
2. The price payable hereunder includes full reimbursement for and
Seller shall be and remain liable for and pay or cause to be paid (or
reimburse Buyer if Buyer shall have paid) all royalties, taxes and other
costs, impositions, burdens and assessments on or with respect to the Gas
sold and delivered hereunder which apply to, accrue or are imposed prior to
and at the final delivery point(s). Buyer warrants that all Gas purchased
under this Agreement is purchased for resale and that, for so long as and
to the extent resales are exempt from sales or like taxes, Buyer shall
furnish Seller applicable certificates of exemption to confirm such Gas is
exempt from sales or like taxes. Seller shall, and hereby warrants that it
will, deliver the Gas sold hereunder free and clear of any such royalties,
taxes, costs, impositions, burdens, and assessments against such Gas,
Seller or Seller's property. Seller shall take all actions necessary to
enable Seller to remit all taxes, costs, impositions, burdens, and
assessments. If Buyer is ever required to remit any such royalties, taxes,
costs, impositions, burdens, and assessments and Buyer is not fully
compensated for same under the express terms of the Base Contract, the
amount thereof shall be deducted from any sums otherwise due to Seller
hereunder or otherwise promptly reimbursed by Seller. SELLER SHALL
INDEMNIFY, DEFEND AND HOLD BUYER HARMLESS FROM AND AGAINST ANY COSTS,
DEMANDS OR LIABILITY FOR ALL SUCH ROYALTIES, TAXES, COSTS, IMPOSITIONS,
BURDENS AND ASSESSMENTS; PROVIDED, HOWEVER, THAT SELLER SHALL PROVIDE THE
DEFENSE OF ALL CLAIMS COVERED HEREBY NOTWITHSTANDING THAT SUCH CLAIMS MAY
ALLEGE THAT BUYER (OR ITS AGENTS) HAS BEEN IN ANY MANNER NEGLIGENT, BUT
THIS INDEMNIFICATION SHALL NOT APPLY TO THE EXTENT IT IS DETERMINED BY A
FINAL NONAPPEALABLE JUDGMENT THAT BUYER'S NEGLIGENCE CAUSED OR CONTRIBUTED
TO THE COSTS, DEMANDS OR LIABILITIES REFERRED TO ABOVE. BUYER SHALL BE
LIABLE FOR AND SHALL PAY, CAUSE TO BE PAID OR REIMBURSE SELLER, IF SELLER
SHALL HAVE PAID, ALL TAXES APPLICABLE TO THE GAS SOLD HEREUNDER AFTER THE
SALE AND DELIVERY AND DOWNSTREAM OF THE FINAL DELIVERY POINT(S), UNLESS
ALLOCATED TO THE SELLER ABOVE OR PURSUANT TO SECTION 3, BELOW.
"Taxes"' as used in this Article IV shall mean any and all ad valorem,
property, occupation, severance, production, gathering, pipeline, gross
production, gross receipts, sales, use, excise and any other taxes,
governmental charges, fees and assessments, excluding only Buyer's
franchise fees and income taxes.
3. It is the mutual intent of the Parties that, as between the Base
Contract and this Agreement, Seller shall bear all costs of performance and
receive the equivalent revenues for same as are paid by WNG under the Base
Contract. In the event that the resale by Buyer of the Gas purchased
hereunder becomes subject to a new sales, excise or similar tax and Buyer
is not permitted to increase its price to WNG under the Base Contract to
recoup that tax payment, then such amount will be deducted by Buyer from
the sums otherwise due Seller hereunder, or shall otherwise be promptly
reimbursed by Seller to Buyer.
ARTICLE V.
DELIVERY POINTS AND DELIVERY PRESSURE
1. The provisions of ARTICLE V of the Base Contract shall apply
mutatis mutandis to this Agreement.
ARTICLE VI.
PAYMENT
1. The provisions of ARTICLE XI of the Base Contract shall apply
mutatis mutandis to this Agreement except that, unless otherwise agreed in
writing, (a) Buyer shall pay Seller on or before ten (10) Business Days
after Buyer receives payment from WNG under the Base Contract, and (b)
Seller shall provide Buyer the monthly statement required by Paragraph 3 of
ARTICLE XI of the Base Contract showing the quantity of Gas delivered by
Seller at each final delivery point.
ARTICLE VII.
QUALITY
1. The provisions of ARTICLE XII of the Base Contract shall apply
mutatis mutandis to this Agreement.
ARTICLE VIII.
MEASUREMENT
1. The provisions of ARTICLE XIII of the Base Contract shall apply
mutatis mutandis to this Agreement.
ARTICLE IX.
FORCE MAJEURE
1. The provisions of ARTICLE XVII of the Base Contract shall apply
mutatis mutandis to this Agreement except that (a) any Force Majeure under
the Base Contract shall be deemed to be Force Majeure under this Agreement
and (b) in the event and to the extent that Seller fails, for any reason
(including, but not limited to, Seller's suffering an event of Force
Majeure), to deliver the requisite quantity of Gas requested by Buyer for
immediate redelivery to WNG at the final delivery point(s), SELLER SHALL
INDEMNIFY, DEFEND AND HOLD HARMLESS BUYER AND ITS AFFILIATES, DIRECTORS,
OFFICERS, EMPLOYEES, AND AGENTS (THE "INDEMNIFIED ENTITIES") FROM AND
AGAINST ANY AND ALL COSTS, DEMANDS OR LIABILITY TO WNG OR TO ANY THIRD
PARTIES CLAIMING BY OR THROUGH WNG ARISING FROM OR RELATING TO SUCH FAILURE
TO DELIVER, IT BEING EXPRESSLY UNDERSTOOD AND AGREED THAT SUCH DUTY TO
INDEMNIFY SHALL APPLY REGARDLESS OF WHETHER THE CLAIMS ARISE IN WHOLE OR IN
PART FROM THE ACTUAL OR ALLEGED COMPARATIVE, CONCURRENT, ACTIVE, PASSIVE OR
CONTRIBUTORY NEGLIGENCE OF ANY OF THE INDEMNIFIED ENTITIES.
ARTICLE X.
NOTICES AND PAYMENTS
1. The provisions of ARTICLE XVIII of the Base Contract shall apply"
mutatis mutandis to this Agreement except that for notice purposes under
this Agreement the following addresses shall be used:
Mesa Operating Co.
Attention: Marketing Department
5205 N. O'Connor Blvd.
Suite 1400
Irving, TX 75039-3746
Williams Gas Marketing Company
Attention: Director, Gas Supply
P.O. Box 3102
Tulsa, OK 74101
ARTICLE XI.
MISCELLANEOUS
1. The provisions of Article XIX of the Base Contract shall apply
mutatis mutandis to this Agreement except that the last sentence of Section
6 and the entirety of Section 7 of Article XIX of the Base Contract shall
have no application, force or effect whatsoever in this Agreement.
2. This Agreement shall not be assigned by Buyer or Seller without
the prior written consent of the other, which consent shall not be
unreasonably withheld.
3. This Agreement, together with the Gas Supply Guarantee, contain
the entire agreement between the Parties relating to the subject matter
hereof and thereof and the Gas covered hereby. All prior agreements,
understandings and representations, whether consistent or inconsistent,
oral or written, concerning the transaction(s) that is the subject of this
Agreement and the Gas Supply Guarantee are merged into and superseded by
this written Agreement and the Gas Supply Guarantee. No modification or
amendment of this Agreement shall be binding on either Party unless in
writing and signed by the Parties.
4. Solely respecting Buyer's sale and delivery obligations
thereunder, the Base Contract is attached hereto as Exhibit A and is
incorporated herein for all purposes.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to
be executed in a number of counterparts, each of which shall be deemed an
original and effective as of the Effective Date above specified.
MESA OPERATING CO., a Delaware
corporation, as successor to
MESA OPERATING LIMITED
PARTNERSHIP, acting on behalf
of and as agent for
HUGOTON CAPITAL LIMITED
PARTNERSHIP, a Delaware WILLIAMS GAS MARKETING
limited partnership COMPANY
By: /s/ Paul W. Cain By: /s/ Ralph A. Hill
------------------------ -------------------------
Paul W. Cain Ralph A. Hill
President and Chief Vice President and
Operating Officer General Manager
<PAGE>
GAS SUPPLY GUARANTEE
As an inducement to Mesa Operating Co., a Delaware corporation, as
successor to Mesa Operating Limited Partnership, acting on behalf of and as
agent for Hugoton Capital Limited Partnership, a Delaware limited
partnership ("Buyer"), to enter into that certain Gas Supply Agreement
between Buyer and Williams Gas Marketing Company ("Seller") dated May 11,
1994 (the "Supply Agreement") and for other good and valuable
consideration, the receipt and adequacy of which are hereby acknowledged,
Williams Field Services Group, Inc., a Delaware corporation ("Guarantor")
hereby absolutely and unconditionally guarantees to Buyer:
(a) the performance by Seller of the terms, covenants and conditions of
the above-referenced Supply Agreement provided it is understood that
Guarantor may cause the Supply Agreement to be performed by Guarantor's
designee, whether such designee is affiliated or not; and
(b) the payment by Seller of all amounts required by the Supply
Agreement to be paid by Seller to Buyer (collectively, the "Obligations").
Upon the occurrence of a default in the Obligations, Guarantor will pay to
Buyer upon demand the amount of any loss or damage which Buyer may suffer
by reason of such default, including interest, all expenses of collection
and counsel's fees incurred by Buyer by reason of the default of Seller.
This Guarantee by Guarantor shall remain in full force and effect during
the term of such Supply Agreement, and any extensions or renewals thereof.
This Guarantee shall continue to apply to any Obligations arising under the
Supply Agreement notwithstanding any assignment by Seller of such Supply
Agreement to any entity, whether or not affiliated with Guarantor, provided
that Buyer has consented in writing to such assignment. Notwithstanding the
foregoing, however, this Guarantee shall expire on the same date the
above-referenced Supply Agreement (or the particular rights and Obligations
thereunder) expires or is terminated, whichever is later, and Guarantor
shall not be liable hereunder for Obligations of Seller created, incurred,
contracted or assumed under the Supply Agreement after the termination or
expiration of such Agreement; provided, however such expiration shall not
affect, in any manner, rights arising under this Guarantee with respect to
Obligations which shall have been created, incurred, contracted or assumed
under such Supply Agreement prior to the same date the above-referenced
Supply Agreement, expires or is terminated.
Guarantor hereby (a) waives (i) promptness, diligence, presentment,
protest, notice of dishonor, notice of intent to accelerate, notice of
acceleration, notice of acceptance and any and all other notices with
respect to any of the Obligations or this Guarantee, (ii) the filing of any
claim with a court in the event of receivership or bankruptcy of Seller,
(iii) protest or notice with respect to nonperformance or nonpayment of all
or any of the Obligations, (iv) all demands whatsoever (and any requirement
that same be made on Seller, any of its subsidiaries or any other person as
a condition precedent to Guarantor's Obligations hereunder); and (b)
covenants and agrees that this Guarantee will not be discharged except by
complete performance of the Obligations and any payment Obligations of
Guarantor contained herein.
If, in the exercise of any of its rights and remedies, Buyer shall forfeit
any of its rights or remedies, including, without limitation, its right to
enter a deficiency judgment against Seller, any of its subsidiaries or any
other person, whether because of any applicable law pertaining to "election
of remedies" or otherwise, Guarantor hereby consents to such action by
Buyer and waives any claim based upon such action. Any election of remedies
which results in the denial or impairment of the right of Buyer to seek a
deficiency judgment against Seller shall not impair the Obligations of
Guarantor to pay the full amount of the Obligations or any other obligation
of Guarantor contained herein.
This Guarantee shall remain in full force and effect and continue to be
effective should any petition be filed by or against Seller for liquidation
or reorganization, should Seller become insolvent or make an assignment for
the benefit of creditors or should a receiver or trustee be appointed for
all or any significant part of Seller's assets, and shall, to the fullest
extent permitted by law, continue to be effective or be reinstated, as the
case may be, if at any time payment and performance of the Obligations, or
any part thereof, is, pursuant to applicable law, rescinded or reduced in
amount, or must otherwise be restored or returned by any obligee of the
Obligations or such part thereof, whether as a "voidable preference,"
"fraudulent transfer", or otherwise, all as though such payment or
performance had not been made. In the event that any payment, or any part
thereof, is rescinded, reduced, restored or returned, the Obligations
shall, to the fullest extent permitted by law, be reinstated and deemed
reduced only by such amount paid and not so rescinded, reduced, restored or
returned.
Should any clause, sentence, paragraph, subsection or Section of this
Guarantee be judicially declared to be invalid, unenforceable or void, such
decision will not have the effect of invalidating or voiding the remainder
of this Guarantee, and the parties hereto agree that the part or parts of
this Guarantee so held to be invalid, unenforceable or void will be deemed
to have been stricken herefrom and the remainder will have the same force
and effectiveness as if such part or parts had never been included herein.
THIS GUARANTEE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE
INTERNAL LAWS (AS OPPOSED TO CONFLICT OF LAWS PRINCIPLES) AND JUDICIAL
DECISIONS OF THE STATE OF TEXAS AND APPLICABLE FEDERAL LAW.
The obligation of Guarantor is a primary and an unconditional obligation
and covers all Obligations of Seller to Buyer which directly arise under
the Supply Agreement. This obligation shall be enforceable before or after
proceeding against Seller or against any security held by Seller and shall
be effective regardless of: the solvency or insolvency of Seller at any
time; the extension or modification of the indebtedness of Seller by
operation of law or the subsequent incorporation, reorganization, merger or
consolidation of Seller; or any other change in the composition, nature or
location of Seller.
The undersigned officer of Guarantor, in executing this Guarantee,
certifies to Buyer that:
(i) Guarantor is a corporation duly organized and existing in good
standing and has full power and authority to make and deliver
this Guarantee;
(ii) The execution, delivery and performance of the Guarantee by
Guarantor do not require the consent or approval of any other
person and have been duly authorized and does not and will not
violate provisions of or constitute default under, any
presently applicable law or its organizational instruments or
any agreement presently binding on it; and
(iii) This Guarantee has been duly executed and delivered by
authorized officers of Guarantor and constitutes its lawful,
binding and legally enforceable obligation.
(iv) Guarantor has received, or expects to receive, direct or
indirect benefit from the making of this Guaranty.
If a material adverse change occurs after the date hereof in the condition
(financial or otherwise), operations, business, or property of the
Guarantor ("Material Change of Condition"), then the Guarantor shall post a
surety bond in favor of Buyer. Said surety bond shall be in an amount equal
to the total value of that quantity of gas which was subject to call
(whether or not produced or sold) by Williams Natural Gas Company ("WNG')
from Buyer pursuant to that certain Gas Purchase Agreement dated December
1, 1989, as amended, between WNG and Buyer (the "Base Contract") during the
period from November 1 through the following March 31 next preceding the
date on which the Material Change of Condition occurs. For purposes of
determining the total value, the following calculation shall be made for
each month and the monthly calculated amounts then added together to
arrive at the amount of the surety bond:
(i) the posted index price (per MMBtu, dry basis) in Inside FERC's
Gas Market Report under the heading "Williams Natural Gas Co.
(Texas, Oklahoma, Kansas)" as published in the first issue of
the month for each of the months of November through March
shall be multiplied by
(ii) the quantity of Gas subject to call by WNG for each of the
months of November through March pursuant to the Base
Contract.
Seller shall only be required to post such surety bond for as long as the
Material Change of Condition continues.
Notwithstanding the foregoing, and except and to the extent otherwise
provided in (b) of the first grammatical paragraph of this Guarantee, the
Obligations guaranteed by the Guarantor shall never exceed the nature,
extent and amount of the Obligations owed by Seller to Buyer. Any change,
modification, termination, or amendment in or to any Obligation under the
Gas Supply Agreement shall correspondingly determine the nature, extent and
amount of the Obligations guaranteed hereunder by the Guarantor, subject to
the limitations expressed elsewhere herein.
IN WITNESS WHEREOF, this Guarantee is duly executed by Williams Field
Services Group, Inc. this 11th day of May, 1994.
"GUARANTOR"
WILLIAMS FIELD SERVICES GROUP, INC.
By: /s/ (Indecipherable)
------------------------------------------
Title: Vice President
------------------------------------------
INTERRUPTIBLE GAS TRANSPORTATION AND SALES AGREEMENT
----------------------------------------------------
THIS INTERRUPTIBLE GAS TRANSPORTATION AND SALES AGREEMENT is made and
entered into o the 1st day of January, 1991, by and between ENERGAS
COMPANY, a division of Atmos Energy Corporation, a Texas corporation
("Energas"), and MESA OPERATING LIMITED PARTNERSHIP, a Delaware limited
partnership ("Mesa").
W I T N E S S E T H
-------------------
WHEREAS, Energas owns and operates a pipeline system located in the
State of Texas; and
WHEREAS, Energas and Mesa desire to enter into an Agreement providing
for the transportation of gas by Energas for Mesa to the Delivery Point(s),
as hereinafter defined, and the sale of supplemental gas by Energas to
Mesa, all in accordance with the General Terms And Conditions attached
hereto and incorporated herein;
NOW, THEREFORE, in consideration of the mutual covenants contained
herein and other good and valuable consideration, the receipt and
sufficiency of which are hereby acknowledged, the parties hereto agree as
follows:
ARTICLE I
---------
TRANSPORTATION OF GAS FROM FAIN PLANT TO INDUSTRIAL USER
Mesa has gas produced pursuant to the "B" Contract and processed at
the Fain Plant operated and owned by Mesa in excess of Energas' demand for
supply pursuant to that Agreement dated June 27, 1949, as amended, between
Energas and Mesa (as successors to Amarillo Gas Company and Amarillo Oil
Company) available to Mesa for its industrial users in the City of Amarillo
and its environs (hereinafter "Excess Gas"). The terms and conditions
under which such Excess Gas will be transported by Energas for Mesa from
the tailgate of the Fain Plant to the ultimate delivery point for its
industrial users are herein defined and agreed upon. In this regard, Mesa
and Energas agree that Energas shall accept custody of such Excess Gas made
available at the Fain Plant tailgate and provide the necessary
transportation services from the tailgate of the Fain plant to the delivery
point designated by Mesa and located in the City of Amarillo and its
environs for a transportation fee as set forth herein.
ARTICLE II
----------
TRANSPORTATION OF GAS FROM FAIN PLANT TO WESTAR INTERCONNECT
------------------------------------------------------------
In addition to the transaction described under Article I above, Mesa
and Energas agree and acknowledge that the total volume of gas made
available at the tailgate of the Fain Plant at certain times is in excess
of Energas' demand for gas in the City of Amarillo and its environs, and
also in excess, temporarily or otherwise, of the gas supply requirements of
Mesa to satisfy contractual commitments to its industrial users in the City
of Amarillo and its environs. The Excess Gas made available at the Fain
Plant may, at Mesa's sole discretion, be taken by it for eventual placement
in storage, exchange, or for the sale to customers in the City of Amarillo
and its environs (but only those customers averaging not less than
1 MMCFD as provided in Article VIII hereof. As to any of the possible
transactions described in Articles I and II, the Excess Gas required by
Mesa to satisfy its industrial users will be transported by Energas
(whenever Energas has available transportation capacity) from the tailgate
of the Fain Plant to the designated interconnect on Westar Transmission
Company's (hereinafter referred to as "Westar") pipeline system from which
Westar will perform such additional services as may be mutually agreed upon
as between Mesa and other parties, including Westar. In this regard, Mesa
and Energas agree that Energas shall accept custody of such gas made
available at the Fain Plant tailgate and thereafter provide the necessary
transportation services from the tailgate of the Fain Plant to the Amarillo
Creek interconnect (commonly known as Amarillo Creek located in the SW/4 of
Section 20, G&M Survey, Block M-3, Potter County, Texas) or such other
interconnect(s) to be mutually agreed upon for a transportation fee as set
forth herein.
ARTICLE III
-----------
TRANSPORTATION OF STORAGE OR EXCHANGE GAS REDELIVERED
----------------------------------------------------
TO MESA FROM WESTAR
-------------------
Mesa and Energas agree and acknowledge that from time to time Mesa may
desire that volumes of gas placed in Westar's storage facilities, pursuant
to the transaction described in Article II above, be redelivered to it by
Westar to the Kalka interconnect (commonly known as Kalka, located in the
SW/4 of Section 19, AS&M Survey, Potter County, Texas) or other
interconnect(s) to be mutually agreed upon on Energas' pipeline system.
Therefore, contemplating that such redelivered gas volumes would require
transportation services to be performed by Energas from such Energas/Westar
interconnect to mutually agreeable delivery point(s), Mesa and Energas
agree that Energas shall provide the necessary transportation service from
such Energas/Westar interconnect(s) to such delivery point(s) within the
City of Amarillo and its environs for a transportation fee as set forth
herein. Energas shall accept custody of such gas made available at such
Energas/Westar interconnect(s) and transport and redeliver such volumes of
gas to such delivery point(s). Furthermore, and in addition to the
transaction contemplated herein, Energas acknowledges that exchange gas
(gas required to be redelivered to Mesa on the basis of prior gas delivered
to such third party by Mesa) may be redelivered to Mesa by a third party
other than Westar, and that said third party would endeavor to redeliver
certain required volumes of gas through pipeline facilities owned by it or
by others to a point of interconnect with Energas' pipeline system. In
this event, and not unlike the transportation services to be performed by
Energas as to redelivered stored volumes of gas, Energas agrees to
transport said gas volumes made available from the point(s) of interconnect
on Energas' pipeline system, including the Kalka interconnect, to such
delivery point(s) within the City of Amarillo and its environs for a
transportation fee as set forth herein.
ARTICLE III
-----------
TRANSPORTATION OF STORAGE OR EXCHANGE GAS REDELIVERED
-----------------------------------------------------
TO MESA FROM WESTAR
-------------------
Mesa and Energas agree and acknowledge that from time to time Mesa may
desire that volumes of gas placed in Westar's storage facilities, pursuant
to the transaction described in Article II above, be redelivered to it by
Westar to the Kalka interconnect (commonly known as Kalka, located in the
SW/4 of Section 19, AB&M Survey, Potter County, Texas) or other
interconnect(s) to be mutually agreed upon on Energas' pipeline system.
Therefore, contemplating that such redelivered gas volumes would require
transportation services to be performed by Energas from such Energas/Westar
interconnect to mutually agreeable delivery point(s), Mesa and Energas
agree that Energas shall provide the necessary transportation services
from such Energas/Westar interconnect(s) to such delivery point(s) within
the City of Amarillo and its environs for a transportation fee as set forth
herein. Energas shall accept custody of such gas made available at such
Energas/Westar interconnect(s) and transport and redeliver such volumes of
gas to such delivery point(s). Furthermore, and in addition to the
transaction contemplated herein, Energas acknowledges that exchange gas
(gas required to be redelivered to Mesa on the basis of prior gas delivered
to such third party by Mesa) may be redelivered to Mesa by a third party
other than Westar, and that said third party would endeavor to redeliver
certain required volumes of gas through pipeline facilities owned by it or
by others to a point of interconnect with Energas' pipeline system. In this
event, and not unlike the transportation services to be performed by
Energas as to redelivered stored volumes of gas, Energas agrees to
transport said gas volumes made available from the point(s) of interconnect
on Energas' pipeline system, including the Kalka interconnect, to such
delivery point(s) within the City of Amarillo and its environs for a
transportation fee as set forth herein.
ARTICLE IV
----------
TRANSPORTATION OF NON "B" CONTRACT GAS FROM
-------------------------------------------
VARIOUS ENERGAS INTERCONNECTS
-----------------------------
In addition to Mesa's requirements for transportation under Articles
I, II, and III above (Fain Plant to industrial user, Fain Plant to Westar
interconnect, storage and exchange gas), Mesa also desires to avail itself
of Energas' transportation services relevant to Non "B" Contract gas which
may be produced, purchased or obtained through an exchange by Mesa for
consumption in the City of Amarillo and its environs. In the event of such
occurrence(s) and only in the event that gas is not available or is
inadequate under Articles I and III, Mesa may endeavor to have such gas
transported or otherwise exchanged to a point intersecting with an Energas
interconnect, thus requiring transportation services by Energas from such
point of interconnect to points of delivery for Mesa's industrial gas users
located within the City of Amarillo and its environs. Therefore, and not
unlike the transportation services to be performed by Energas as to gas
described in Article III above, Energas agrees to transport said gas
volumes made available subject to the conditions set forth above from the
selected point of interconnect on Energas' pipeline system to mutually
agreeable delivery point(s) located within the City of Amarillo and its
environs for a transportation fee set forth herein.
ARTICLE V
---------
PRICING FORMULA FOR REDELIVERIES OF "B" CONTRACT GAS
----------------------------------------------------
It is agreed to and acknowledged by Mesa and Energas that all volumes
of gas taken by Mesa in excess of Energas' daily demand for gas pursuant to
the above-referenced 1949 Agreement, as amended, as well as gas taken by
Mesa at the tailgate of the Fain Plant and stored or exchanged outside the
City of Amarillo and its environs, must eventually be returned for
consumption in the City of Amarillo and its environs. Although this
balancing of gas volumes need not occur within any particular time frame
and can only be initiated by Mesa as opposed to Energas, it is important
that Mesa and Energas agree upon the procedure under which the redelivered
"B" Contract gas may be purchased by Energas if offered by Mesa.
Therefore, if such "B" Contract gas is offered to Energas by Mesa, such
offer shall be in writing and set forth the price, volume, terms and other
provisions under which Mesa is willing to sell such gas. Energas, in turn,
shall have ten (10) days from the receipt of such notice in writing to
either accept or propose a counteroffer. If Energas does not respond to
such an offer within the said time frame, it will be deemed rejected.
Notwithstanding any provision contained herein to the contrary, under
no circumstance shall Energas be obligated to pay Mesa a price per MCF for
such redelivered gas which is in excess of that price then in existence
under the terms and conditions contained within that certain Agreement
previously referenced herein, and dated June 27, 1949, and all amendments
which have been or may be made thereto.
ARTICLE VI
----------
ENERGAS' PURCHASES OF GAS FOR ITS CUSTOMERS
-------------------------------------------
Mesa and Energas agree and acknowledge that pursuant to that certain
Assignment dated October 18, 1983, by and between Pioneer Corporation,
Energas Company, and Amarillo Oil Company, Energas succeeded to the June
27, 1949, Gas Purchase Agreement, as amended, and obligated itself to
purchase and take all volumes of gas made available by Pioneer (Mesa, as
successor) to service customers in the City of Amarillo and its environs.
Furthermore, Energas agrees that as to all future industrial sales entered
into subsequent to the date hereof, Energas shall be obligated to purchase
all such required volumes of gas from Mesa at a mutually agreeable price.
However, Energas acknowledges that Mesa shall be under no obligation to
sell such gas to Energas for its industrial customers in the event the
price and terms offered to Mesa are unacceptable to Mesa. If Mesa rejects
a request by Energas to purchase gas as aforesaid, then Energas may acquire
such desired volumes for its industrial customers from any source it may
select at a price equal to or lower than that offered to Mesa.
Although Mesa and Energas fully acknowledge and reaffirm Energas'
obligation as set forth under the Assignment referred to above, Mesa agrees
to release, and hereby does release and forever discharge, Energas and
EnerMart Inc. from any and all breaches or alleged breaches, if any, and
any and all claims of such breaches or alleged breaches of the
above-referenced 1949 Agreement, as amended, arising out of or due to any
sales of Non "B" Contract gas made prior to April 1, 1988 by Energas or
EnerMart Inc. to customers located in the City of Amarillo and its
environs.
ARTICLE VII
-----------
MESA'S PURCHASE OF SUPPLEMENTAL GAS
-----------------------------------
Mesa and Energas acknowledge that due to potential shortages of "B"
Contract gas, Fain Plant shut-downs or other conditions not within the
control of Mesa, Mesa may be required to purchase volumes of gas from third
parties in sufficient quantities to supplement or otherwise satisfy its
contractual obligations for the delivery of gas to its industrial users.
In this regard, it is also acknowledged by the parties that the stored or
exchanged gas described within Article III is intended by Mesa to be a
potential source from which Mesa will acquire back-up gas, thus requiring
to gas purchases from a third party source. However, both Mesa and Energas
agree that in the event sufficient gas volumes as described in Article III
are not available to Mesa for any reason, then and in that event, Energas
agrees to sell, if available, sufficient supplemental volumes of gas to
Mesa from its own back-up gas supplies. In consideration for the delivery
of such gas by Energas to Mesa's customers, Mesa agrees to pay Energas a
sum per MCF equal to Energas' Small Industrial Rate Tariff applicable to
the City of Amarillo and its environs, as such Tariff may be amended from
time to time.
ARTICLE VIII
------------
TRANSPORTATION RATES
--------------------
The incremental rates to be charged by Energas for the transportation
services performed hereunder shall be as follows; provided, however, that
Energas shall have no responsibility or obligation whatsoever to provide
transportation services to any industrial user or any other customer
wherein the designated volumes to said user or customer are less than 1
MMCF per day.
The rates are to be applied to volumes actually delivered by Energas
at the industrial users' facility or the system interconnect terminating
the particular delivery transaction pursuant to Articles I, II, III, or IV.
Mesa agrees to, at its election, either provide shrinkage gas in kind, or
reimburse Energas for shrinkage gas for each transaction in an amount
relative to the delivered volumes, equal to the "lost and unaccounted for"
rate for the Energas Amarillo transmission system which for purposes of
this Agreement, the parties have agreed that the shrinkage will be set at
1.5%. If Mesa elects to reimburse Energas for shrinkage rather than
provide shrinkage volume, the shrinkage reimbursement shall be calculated
based upon Energas' Amarillo system weighted average cost of gas for the
pertinent month.
As to gas returned to Energas for further transportation services
pursuant to Articles III and IV hereof, Mesa agrees to inform Energas as to
when such volumes are being returned, the volumes being returned, and the
type of transaction under which the volumes are being returned, such
information to be provided in writing on a monthly basis by the 10th day of
the month following a month in which any such transactions occurred.
<PAGE>
RATES
TOTAL FOR ARTICLES RATES FOR
VOLUMES/YEAR I, II, AND IV ARTICLE III
------------ -------------- -----------
0.000000 BCF to $0.165/MCF $0.04/MCF
2.000000 BCF
2.000001 BCF to $0.120/MCF $0.04/MCF
3.000000 BCF
3.000001 BCF to $0.100/MCF $0.04/MCF
4.000000 BCF
4.000001 BCF to $0.080/MCF $0.04/MCF
6.000000 BCF
6.000001 BCF $0.060/MCF $0.04/MCF
and above
For illustrative purposes only, if Energas were to transport total
volumes of gas for Mesa's account equal to 10.000000 BCF of gas during any
given period (of which 9 BCF was transported under Articles I, II, and IV,
and 1 BCF was transported under Article III, the transportation rate(s) to
be charged to Mesa would be:
2 BCF @ $0.165/MCF
1 BCF @ $0.120/MCF
1 BCF @ $0.100/MCF
2 BCF @ $0.080/MCF
3 BCF @ $0.060/MCF
1 BCF @ $0.040/MCF
--------------
$930,000.00
<PAGE>
ARTICLE IX
----------
INTERRUPTIBLE TRANSPORTATION SERVICES
-------------------------------------
It is mutually understood and agreed as between Mesa and Energas that
all transportation services to be provided by Energas under the entirety of
this Agreement shall be provided on an "interruptible basis" and not
otherwise. In regard to any transportation interruptions, Energas shall
use its best efforts to promptly notify Mesa of any actual or reasonably
foreseeable interruptions so that Mesa can take such action as it may deem
prudent or advisable as to its industrial users.
ARTICLE X
---------
ENERGAS' EXCLUSIVE RIGHT TO TRANSPORT
-------------------------------------
Except as set forth herein Mesa and Energas agree that Energas is
hereby granted the exclusive right to transport the volumes of gas made
available and referred to within the entirety of this Agreement so long as
said Agreement remains in full force and effect. The exclusive rights
granted to Energas herein shall not prohibit the use by Mesa of a third
party's pipeline facilities and related transportation services during
periods when Energas has invoked interruption of its transportation
services, or for the transportation of volumes which on a daily basis
cannot be transported by Energas due to operational constraints of the
Energas Amarillo system.
ARTICLE XI
----------
REGULATORY APPROVAL OF TRANSPORTATION RATES
-------------------------------------------
Mesa and Energas acknowledge that the transportation rates set forth
herein may be challenged or have to be submitted by Energas to certain
regulatory agencies for approval and/or review. In the event the adequacy
of such transportation rates are successfully challenged or are adjusted by
an appropriate regulatory agency, then Mesa agrees, on a prospective basis
only, to reimburse Energas fifty percent (50%) of the difference between
the level of rates determined to be adequate in such a proceeding or
decision and the rates established herein multiplied by the volumes of gas
transported by Energas hereunder subsequent to the effective date of such
new rates. Notwithstanding any provision contained herein to the contrary,
either party may cancel the Agreement if such newly established rates are
deemed unacceptable to such party.
ARTICLE XII
-----------
TERM OF AGREEMENT
-----------------
Unless otherwise terminated pursuant to Article XI, the primary term
of this Agreement will be until December 31, 1994. Thereafter, this
Agreement may remain in effect on an annual basis, provided the parties
mutually agree on all the terms and conditions for each subsequent year.
In this regard, if the parties have been unable to agree on all the terms
and conditions for 1995 by October 1, 1994 (or each subsequent October 1),
this Agreement will automatically terminate at 7:00 A.M. on January 1, 1995
(or each subsequent January 1). This same type of mutual agreement or
termination procedure will be followed as long as this Agreement has not
been previously terminated.
ARTICLE XIII
------------
ENERGAS' STATUS AS PRIVATE CARRIER
----------------------------------
Although Energas has entered into this Agreement based upon
negotiations as between Mesa and Energas, both Mesa and Energas stipulate
and agree that Energas' pipeline system, to be utilized for the
performance of Energas' obligations hereunder, is a private pipeline
system not owned, operated or managed by Energas for the transportation of
natural gas to or for the public for hire, and that this Agreement (and
the transportation services to be provided herein) has been executed by
the parties based in part upon the long- standing contractual obligations
existing as between Mesa and Energas as to the "B" Contract and the
rights and obligations of the parties under that certain Agreement dated
June 27, 1949, as subsequently amended, by and between Amarillo Oil
Company and Amarillo Gas Company, and that it is not Energas' intent or
desire to abandon or otherwise modify or amend its status as a private
carrier.
ARTICLE XIV
-----------
BILLING AND PAYMENT
-------------------
1. On or before the twenty-fifth (25th) day of each calendar month
after deliveries of gas hereunder have commenced, Energas shall render to
Mesa an invoice that shows the total volume and BTU content of gas
delivered and redelivered hereunder during the preceding Billing Month and
the monies due therefor, including any amounts due for shrinkage which
Mesa is obligated under this Agreement to reimburse Energas. Mesa shall
pay such invoice within ten (10) days after Mesa's receipt thereof to the
address of Energas noted on the invoice.
2. In the event Mesa fails to pay the full amount due Energas when the
same becomes due, interest thereon shall accrue from the date that such
payment became due until it is paid in full at the lesser of (a) a rate of
fifteen percent (15%) per annum or (b) the highest lawful rate permitted by
applicable law. If such failure to pay continues for ten (10) days,
Energas may, in addition to any and all other remedies available to
Energas, suspend further deliveries of gas hereunder.
3. All invoices and payments are subject to correction for any errors
contained therein until twelve (12) months after the date Energas received
payment on an incorrect invoice or received an incorrect payment.
ARTICLE XV
----------
ASSIGNMENT
----------
This Agreement may not be assigned by either party hereto without the
prior written consent of the other party, which such consent shall not be
unreasonably withheld; except that no prior consent shall be required for
an assignment to (a) a company owning 100% of, wholly owned by, or having a
common parent with, such assigning party or (b) a trustee or trustees,
individual or corporate, as security for bonds or other obligations or
security, provided, however, that an assignment for security purposes shall
not relieve the assigning party of any of its obligations under this
Agreement.
ARTICLE XVI
-----------
NOTICES
-------
Any notice required to be given under this Agreement or any notice
which either party hereto may desire to give the other party shall be in
writing and shall be considered duly delivered when hand-delivered or when
deposited in the United States mail, postage prepaid, registered or
certified, and addressed as follows:
Energas Company
P. O. Box 650205
Dallas, Texas 75256-0205
Attention: Gas Supply and Ind. Sales
Mesa Operating Limited Partnership
P. O. Box 2009
Amarillo, Texas 79189-2009
Attention: Gas Marketing Department
or such other address as Energas, Mesa, or their respective successors or
assigns shall designate by written notice given in the manner described
above. Routine communications, including monthly invoices, may be mailed
by ordinary mail and are deemed delivered when hand-delivered or when
deposited in the United States mail, postage prepaid, and addressed to the
above-designated name and address.
ARTICLE XVII
------------
PRIOR TRANSPORTATION AND SALES AGREEMENT TERMINATED
---------------------------------------------------
1. Energas and Mesa hereby expressly terminate that certain
Interruptible Gas Transportation and Sales Agreement dated and effective
April 1, 1988, as amended and supplemented.
ARTICLE XVIII
-------------
MISCELLANEOUS
-------------
1. It is expressly agreed that this Agreement does not modify or
amend in any way the obligations of the parties under the June 27, 1949,
Gas Purchase Agreement, as amended, and any summary, characterization or
statement in this Agreement concerning those obligations are for
convenience only and are not intended to change or amend the June 27,
1949, Gas Purchase Agreement, as heretofore amended.
2. All the terms and conditions of this Agreement were prepared
jointly by the parties hereto and not by any party to the exclusion of the
other.
3. Neither Mesa nor Energas shall be held responsible or liable for
damages for acts or conduct of the other, and each party shall indemnify
and hold harmless the other from claims or demands on account thereof
except to the extent such damages were caused by the action or inaction of
the other party.
4. Notwithstanding the provisions of the above, each party hereto
shall be responsible for all gas which is in its possession. The party
then in possession shall indemnify and hold harmless the other from all
claims or demands on account of all injuries to persons or property caused
by or arising from said gas except to the extent such injuries or damages
were caused by the action or inaction of the other party.
5. This Agreement shall be subject to all valid, relevant, present
and future state and federal laws, decisions or courts of competent
jurisdictions and all rules, regulations and orders of any regulatory
authority having jurisdiction. This Agreement shall be further governed
by, construed and enforced in accordance with and subject to the laws of
the State of Texas, without regard to its conflict of law, rules and/or
principles.
6. The parties expressly agree that this Agreement is not intended to
benefit any third party(ies) and shall not do so. This Agreement shall not,
at any time, give rise to any claim, demand, or cause of action, whether
known or unknown or contingent or absolute at this time or at any other
time, by any such third party(ies) claiming third party beneficiary rights
hereunder.
7. This Agreement contains the entire agreement between the parties
and supersedes any and all prior agreements, arrangements and
understandings between the parties relating to the transportation of the
gas by Energas for Mesa as discussed herein. This Agreement cannot be
modified or terminated orally.
8. The failure of either party hereto at any time to require
performance by the other party of any provision hereof shall in no way
affect the right of such party thereafter to enforce the same, nor shall
the waiver by either party hereto of any breach of any provision hereof by
the other party be taken or held to be a waiver by such party of any
succeeding breach of such provision, or as a waiver of the provision
itself.
9. Energas and Mesa agree to hold in confidence and not disclose the
terms of this Agreement or other information pertaining to it except as
required for financial reporting, tax, regulatory commissions, The
Securities and Exchange Commission, or other purposes for which disclosure
is legally compulsory on the part of the disclosing party.
10. If any provision, term, or condition in this Agreement shall be
held invalid, illegal, or unenforceable by any regulatory agency or
tribunal of competent jurisdiction, upheld by appellate court, if
appealed, the validity, legality and enforceability of the remaining
provisions, terms and conditions shall not in any way be affected or
impaired thereby.
IN WITNESS WHEREOF, the parties hereto have executed this
Interruptible Gas Transportation and Sales Agreement as of the date first
above written which replaces that certain Interruptible Gas Transportation
and Sales Agreement dated April 1, 1988 as amended and supplemented.
ENERGAS COMPANY MESA OPERATING LIMITED PARTNERSHIP
a division of Atmos By: Pickens Operating Co., General Partner
Energy Corporation
By: /s/ Toby A. Priolo By: /s/ Claude B. Jenkins
------------------ ---------------------------------------------
Toby A. Priolo Claude B. Jenkins
Vice President Vice President-Marketing
<PAGE>
GENERAL TERMS AND CONDITIONS
TO
INTERRUPTIBLE GAS TRANSPORTATION AND SALES AGREEMENT
----------------------------------------------------
For purposes of these Terms and Conditions, unless the context hereof
requires otherwise, the following definitions shall be applicable:
Section 1.1. The terms "gas" shall mean natural gas produced from gas
-----------
wells (i.e., gas-well gas), gas produced in association with oil (i.e.,
casinghead gas), and the residue gas resulting from the processing of both
casinghead gas and gas-well gas.
Section 1.2. The term "day" shall mean the twenty-four (24) hour
-----------
period commencing at 8:00 a.m., Central Time, on one calendar day and
ending at 8:00 a.m. Central Time, on the following calendar day.
Section 1.3. The term "month" or "Billing Month" shall mean the
-----------
period extending from 8:00 a.m., Central Time, on the first day of one
calendar month to 8:00 a.m., Central Time, on the first day of the next
succeeding calendar month, except that the first Billing Month shall
commence on the date of the initial delivery of gas hereunder and shall end
at 8:00 a.m., Central Time, on the first day of the next succeeding
calendar month.
Section 1.4. The term "MCF" shall mean one thousand (,000) cubic
-----------
feet at a temperature of 60 degree Fahrenheit and at an absolute pressure
of 14.65 pounds per square inch.
Section 1.5. The term "BTU" shall mean British thermal unit and
-----------
represents the quantity of heat required to raise the temperature of one
(1) pound avoirdupois of pure water from 58.5 degree Fahrenheit to 59.5
degree Fahrenheit at a constant pressure of 14.73 psia.
Section 1.6. The term "Energas" shall mean Energas Company, a
-----------
division of Atmos Energy Corporation, and the term "MESA" shall mean MESA
Operating Limited Partnership. Energas and MESA are the only parties to
these Terms and Conditions and the related Interruptible Gas Transportation
and Sales Agreement.
Section 1.7. The term "heating value" shall mean the number of BTUs
-----------
produced by the complete combustion, at a temperature of 60 degree
Fahrenheit if saturated with water vapor and at a constant pressure of
14.73 psia and under standard gravitational force (acceleration 980.665 cm
per sec per) with air of the same temperature and pressure as the gas when
the products of combustion are cooled to the initial temperature of the gas
and air and when the water formed by combustion is condensed to the liquid
state.
Section 1.8. The term "psia" shall mean pounds per square inch
-----------
absolute.
Section 1.9. The term "Receipt Point(s)" shall mean the point(s) at
-----------
which gas is delivered by MESA to Energas for transportation pursuant to
the Agreement.
Section 1.10. The term "Delivery Points(s)" shall mean the point(s)
------------
at which Energas shall redeliver gas to or on behalf of MESA pursuant to
the Agreement.
Section 1.11. The term "Agreement" or "the Agreement" as used
------------
throughout the entirety of this document shall mean the January 1, 1991
Interruptible Gas Transportation and Sales Agreement.
ARTICLE II
Pressure
-------
Section 2.1. Deliveries of gas by MESA at the Receipt Point(s) and
-----------
redeliveries of gas by Energas at the Delivery Point(s) shall be made at
pressures mutually agreeable by the parties hereto and sufficient to effect
delivery into the facilities of the party receiving such gas at such
points; provided, however, that neither party shall be required to install
or operate any compression facilities in order to deliver the as at any
specific pressure.
ARTICLE II
Pressure
--------
Section 2.1. Deliveries of gas by MESA at the Receipt Point(s) and
-----------
redeliveries of gas by Energas at the Delivery Points(s) shall be made at
pressures mutually agreeable by the parties hereto and sufficient to effect
delivery into the facilities of the party receiving such gas at such
points; provided, however, that neither party shall be required to install
or operate any compression facilities in order to deliver the gas at any
specific pressure.
ARTICLE III
Measurement of Gas
------------------
Section 3.1. Unless otherwise specifically provided herein, the unit
-----------
of volume for purposes of the measurement of gas delivered hereunder at the
Receipt Point(s) shall be one (1) Mcf
<PAGE>
AMENDMENT TO
------------
INTERRUPTIBLE GAS TRANSPORTATION AND SALES AGREEMENT
----------------------------------------------------
THIS AGREEMENT, is made and entered into as of the 1st day of January,
1995, by and between ENERGAS COMPANY, a division of ATMOS ENERGY
CORPORATION, a Texas corporation, hereinafter referred to as "Energas" and
MESA OPERATING CO., a Delaware corporation, hereinafter referred to as
"MESA";
W I T N E S S E T H
WHEREAS, on January 1, 1991, Energas and MESA entered into an
Interruptible Gas Transportation and Sales Agreement ("Agreement"), whereby
Energas would transport gas for MESA and make emergency gas sales to MESA,
and
WHEREAS, Energas and MESA desire to amend said Agreement dated January
1, 1991, to extend the Term thereof and to provide for certain other
changes.
NOW THEREFORE, in consideration of the mutual agreements of the
parties, Energas and MESA agree as follows:
1. Except for Article VI, all references to that "Agreement dated
June 27, 1949," or substantially similar type references, shall be
deleted and "Amarillo Supply Agreement dated January 2, 1993"
substituted therefore.
2. The parenthetical phrase in lines 9 and 10 of Article II on page 2
is hereby deleted.
3. The first sentence of Article V is hereby deleted and the
following is substituted therefore:
"It is agreed to and acknowledged by MESA and Energas that
with respect to those volumes of "B" Contract gas taken by MESA in
excess of Energas' first call rights pursuant to the Amarillo
Supply Agreement dated January 2, 1993, which are taken by MESA at
the tailgate of the Fain Plant and stored or exchanged outside the
City of Amarillo and its environs, MESA is to cause, like volumes
of gas to be made available, under certain conditions, in the City
of Amarillo and its environs.
4. ARTICLE VI. ENERGAS' PURCHASES OF GAS FOR ITS CUSTOMERS and is
hereby deleted in its entirety and the following Article VI
substituted therefore.
ARTICLE VI
----------
ENERGAS' AND ENERMARTS PURCHASES OF GAS FOR THEIR CUSTOMERS
----------------------------------------------------------
MESA agrees to release, and hereby does release and forever discharge,
Energas and EnerMart Inc. from any and all breaches or alleged breaches, if
any, and any and all claims of such breaches or alleged breaches of the
June 27, 1949 Amarillo Supply Agreement, as amended, arising out of or due
to any sales of Non 'B' Contract gas made prior to April 1, 1988 by Energas
or EnerMart Inc. to customers located in the City of Amarillo and its
environs.
5. ARTICLE VIII. TRANSPORTATION RATES is hereby deleted in its
------------ --------------------
entirety and the following Article VIII is substituted therefore:
"ARTICLE VIII
------------
TRANSPORTATION RATES
--------------------
The rates to be charged by Energas for the transportation services
performed hereunder shall be as set forth in this ARTICLE VIII; provided,
however, that Energas shall have no responsibility or obligation whatsoever
to provide transportation services to any industrial user or any other
customer wherein the designated volumes to said user or customer are less
than 1 MMCF per day.
The rates are to be applied to volumes actually delivered by Energas
at the industrial users' facility or the system interconnect terminating
the particular delivery transaction pursuant to Articles I, II, III, or IV.
MESA agrees, at its election, to either provide shrinkage gas in kind, or
reimburse Energas for shrinkage gas for each transaction in an amount
relative to the delivered volumes, equal to the lesser of the actual "lost
and unaccounted for" rate for the Energas Amarillo transmission system or
1.5%. If MESA elects to reimburse Energas for shrinkage rather than
provide shrinkage volume, the shrinkage reimbursement shall be calculated
based upon Energas' Amarillo system weighted average cost of gas for the
pertinent month.
As to gas returned to Energas for further transportation services
pursuant to Articles III and IV hereof, MESA agreed to inform Energas as to
when such volumes are being returned, the volumes being returned, and the
type of transaction under which the volumes are being returned. Such
information is to be provided in writing on a monthly basis, by the 10th
day of the month following a month in which any such transactions occurred.
The transportation rates per MCF applicable under Articles I, II and
IV shall ultimately be determined on a calendar year basis, but shall
initially be billed to and paid for by MESA on a First Tier Rate basis
because the amount of calendar year volumes so transported by Energas will
not be know until year end. Periodically during the calendar year, but no
less than twice each year, the parties shall meed to determine the actual
volumes transported and to adjust the forecast of volumes to be transported
by Energas for MESA during the remainder of the year. From these meeting
the parties shall attempt to determine when the First Tier volumes have
been transported for the current year and consequently when any Second Tier
Volume transportation and Second Tier Rates apply if any. for purposes of
ultimately applying the First tier Rate (5.5 cents/MCF) or any Second tier
Rate (5.0 cents/MCF), the parties shall no later than sixty (60) days after
the end of the calendar year, determine the total calendar year volumes of
gas actually so transported by Energas and make a payment adjustment
without interest.
For the First Tier volumes transported by Energas on a calendar basis
for MESA pursuant to Articles I, II, and IV, the First Tier Rate shall
ultimately apply. For those volumes so transported which exceed the First
Tier Volumes (Second Tier Volumes), the Second Tier Rate shall ultimately
apply. For all gas transported by Energas for MESA pursuant to Article
III, a Third Tier Rate of 4.0 cents/MCF per month shall apply.
6. ARTICLE ENERGAS' EXCLUSIVE RIGHT TO TRANSPORT, is hereby
deleted in its entirety and the following is substituted
therefore.
"ARTICLE X
----------
ENERGAS' RIGHT TO TRANSPORT
---------------------------
Except as set forth herein, MESA and Energas agree that Energas is
hereby granted the right to transport one hundred percent (100%) of the
First Tier volumes so long as this Agreement remains in full force and
effect. The term "First Tier Volumes" as used herein shall mean fifty
percent (50%) of the "Excess Gas" described in Articles I and II and fifty
percent (50%) of the non-B-Contract gas described in Article IV which Mesa
sells annually to its existing customers for industrial consumption in the
City of Amarillo and its environs. Such rights granted to Energas herein
shall not prohibit the use by MESA of a third party's pipeline facilities
and related transportation services during periods when Energas has invoked
interruption of its transportation service, or for the transportation of
volumes which on a daily basis cannot be transported by Energas due to
operational constraints of the Energas Amarillo system."
7. ARTICLE XII TERM OF AGREEMENT is hereby deleted in its entirety
----------- -----------------
and the following is substituted therefore:
"ARTICLE XII
------------
TERM OF AGREEMENT
-----------------
Unless otherwise terminated pursuant to Article XI, the primary term
of this Agreement will be until December 31, 1999."
8. This Agreement, as amended herein, shall remain in full force
and effect.
IN WITNESS WHEREOF, Energas and MESA have caused this Agreement to be
executed and effective as of the day and year first written above.
ENERGAS COMPANY MESA OPERATING CO.
A Division of
Atmos Energy Corporation
By: /s/ Toby A. Priolo By: /s/ Paul W. Cain
------------------------ ------------------------
Toby A. Priolo
Title: Vice President Title: President & Chief Operating Officer
--------------------- -----------------------------------
Atmos Energy Corporation
EXHIBIT 22
MESA INC.
Subsidiaries
As of December 31, 1995 Place of Incorporation
- ----------------------- ----------------------
Subsidiary Corporations:
Garretson Equipment Co., Inc. Iowa
Hugoton Capital Corporation Delaware
Hugoton Management Company Texas
Mesa Capital Corporation Delaware
Mesa Environmental Ventures Co. Delaware
Mesa Holding Co. Delaware
Mesa Operating Co. Delaware
Mesa Transmission Co. Delaware
Pioneer Natural Gas Company Texas
Pioneer Production Corporation International Texas
Pioneer Uravan, Inc. Texas
Subsidiary Limited Partnership:
Hugoton Capital Limited Partnership Delaware
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND> THIS SCHEDULE CONTAINS SUMMARY FINANCIAL
INFORMATION EXTRACTED FROM THE MESA INC. AND
SUBSIDIARIES DECEMBER 31, 1995, FINANCIAL
STATEMENTS AND IS QUALIFIED IN ITS ENTIRETY
BY REFERENCE TO SUCH FINANCIAL STATEMENTS
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> DEC-31-1995
<CASH> 149,143
<SECURITIES> 38,280
<RECEIVABLES> 47,713
<ALLOWANCES> 2,979
<INVENTORY> 3,387
<CURRENT-ASSETS> 236,747
<PP&E> 1,941,766
<DEPRECIATION> 859,077
<TOTAL-ASSETS> 1,464,696
<CURRENT-LIABILITIES> 192,946
<BONDS> 1,135,330
0
0
<COMMON> 640
<OTHER-SE> 66,364
<TOTAL-LIABILITY-AND-EQUITY> 1,464,696
<SALES> 234,959
<TOTAL-REVENUES> 234,959
<CGS> 0
<TOTAL-COSTS> 186,994
<OTHER-EXPENSES> 105,533
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 148,630
<INCOME-PRETAX> (57,568)
<INCOME-TAX> 0
<INCOME-CONTINUING> (57,568)
<DISCONTINUED> 0
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<NET-INCOME> (57,568)
<EPS-PRIMARY> (.90)
<EPS-DILUTED> (.90)
</TABLE>
SUMMARY REPORT
dated
FEBRUARY 28, 1996
on
RESERVES and REVENUE
as of
DECEMBER 31, 1995
from
CERTAIN PROPERTIES
owned by
MESA OPERATING CO.
MESA HOLDING CO.
and
HUGOTON MANAGEMENT CO.
MESA Inc. has prepared estimates, as of December 31, 1995, of the extent
and value of the proved crude oil, condensate, natural gas liquids, natural
gas, helium, and carbon dioxide reserves of certain properties owned by
Mesa Operating Co. (MOC), Mesa Holding Co. (MHC) and Hugoton Management Co.
(HMC). MESA Inc., a Texas corporation, is the sole owner of three
subsidiary corporations as of the date hereof. These three subsidiaries
are:
1. MOC, which holds title to most of the appraised properties and a
98.6 percent interest in Hugoton Capital Limited Partnership
(HCLP);
2. MHC, which holds .9 percent of HCLP; and
3. HMC, which holds .5 percent of HCLP.
Together, MOC, MHC and HMC own 100 percent of HCLP, which owns most of the
appraised properties in the Hugoton and Panoma fields. Tabulations of
reserves and revenue from the Texas Panhandle properties, all minor
properties, and Mesa Offshore Trust properties included in this report show
the interest of MESA Inc. while tabulations of reserves and revenue from
the Hugoton Area and the Mesa Royalty Trust properties show the collective
interests of Hugoton Capital Limited Partnership hereinafter referred to as
"HCLP". The properties appraised are in the property groups listed below.
The HCLP Hugoton Area - Kansas Hugoton and Panoma Fields
HCLP Share - Mesa Royalty Trust Properties
The Hugoton Area (non-HCLP Royalties)
The Texas Panhandle - Contract "B" and Royalty
The Texas Panhandle - Other
Remaining MESA interests in the Mesa Offshore Trust Properties.
The Gulf Coast Area
The Rocky Mountain Area
The HCLP share - Mesa Royalty Trust Properties are located in the Hugoton
and Panoma fields in Kansas. These properties are burdened by a 10.29282
percent net royalty interest owned by the Mesa Royalty Trust and a .0057
percent overriding royalty interest owned by others. The remaining MESA
Inc. interests in the Mesa Offshore Trust Properties consist of the
remaining interests of MESA Inc. after the transfer (effective December 1,
1982) to the Mesa Offshore Royalty Partnership, a partnership owned 99.99
percent by the Mesa Offshore Trust, of a 90 percent net profits interest in
10 MESA Inc. leases located in the Gulf of Mexico offshore from Louisiana
and Texas.
The reserve estimates are based on a detailed study of MESA Inc.'s
properties. The method or combination of methods utilized in the analysis
of each reservoir was tempered by experience in the area, stage of
development quality and completeness of basic data, and production history.
Reserves in this report are expressed as net reserves. Gross reserves are
defined as the total estimated petroleum hydrocarbons including helium
remaining to be produced after December 31, 1995. Net reserves are defined
as that portion of the gross reserves attributable to the interest owned by
MESA Inc. after deducting royalties and other interests owned by others.
In making these reserve estimates, all interest reversions were taken into
account.
Values shown herein are expressed in terms of future gross revenue, future
net revenue, and present worth. Future gross revenue is that revenue which
will accrue to the appraised interests from the production and sale of the
estimated net reserves. Future net revenue is calculated by deducting
estimated production taxes, ad valorem taxes, operating expenses, and
capital costs from the future gross revenue. Future income tax expenses
were not taken into account in the preparation of these estimates. Present
worth is defined as future net revenue discounted at a specified arbitrary
discount rate compounded monthly over the expected period of realization.
In this report, present worth values using a discount rate of 10 percent
are reported.
Estimates of reserves and future net revenue should be regarded only as
estimates that may change as further production history and additional
information become available. Not only are such reserve and revenue
estimates based on that information which is currently available, but such
estimates are also subject to the uncertainties inherent in the application
of judgmental factors in interpreting such information.
Data used in the preparation of MESA Inc.'s portion of this report were
obtained from MESA Inc.'s records and from reports filed with the
regulatory agencies of the states or areas in which the properties are
located.
The development status shown herein represents the status applicable on
December 31, 1995. In the preparation of the study, data available from
wells drilled on the appraised properties through December 31, 1995 were
used in estimating gross ultimate recovery. Gross production estimated to
December 31, 1995, was deducted from gross ultimate recovery to arrive at
the estimates of gross reserves. In some fields, this required that the
production rates be estimated for up to seven months since production data
for certain properties were available only through May 1995.
Reserves and revenue values shown in this report for the HCLP Share - Mesa
Royalty Trust Properties and the Remaining MESA Inc. interests in the Mesa
Offshore Trust Properties were estimated from projections of reserves and
revenue attributable to the combined HCLP Share and Mesa Royalty Trust
interests or the combined Remaining MESA Inc. and Mesa Offshore Royalty
Partnership interests. Reserves attributable to the trust interests in
each of the royalty trusts were estimated by allocating a portion of the
estimated combined net reserves of each of the property groups based on
future net revenue. The estimated reserves for each of the trusts were
subtracted from the combined net reserves for each trust to arrive at the
estimated reserves of MESA Inc. and HCLP in the trust properties.
Since the reserve volumes attributable to the MESA Inc. interests in the
trust properties are estimated using an allocation of reserves based on
estimates of future revenue, a change in prices or costs will result in
changes in the estimated reserves of MESA Inc. and HCLP.
Petroleum reserves included in this report are classified as proved and are
judged to be economically producible in future years from known reservoirs
under existing economic and operating conditions and assuming continuation
of current regulatory practices using conventional production methods and
equipment. In the analyses, reserves were estimated only to the limit of
economic rates of production under existing economic and operating
conditions using prices and costs as of the date the estimate is made,
including consideration of changes in existing prices provided only by
contractual arrangements but not including escalations based upon future
conditions. The petroleum reserves are classified as follows:
Proved - Reserves that have been proved to a high degree of
certainty by analysis of the producing history of a reservoir
and/or by volumetric analysis of adequate geological and
engineering data. Commercial productivity has been established
by actual production, successful testing, or in certain cases by
favorable core analyses and electrical-log interpretation when
the producing characteristics of the formation are known from
nearby fields. Volumetrically, the structure, areal extent,
volume, and characteristics of the reservoir are well defined by
a reasonable interpretation of adequate subsurface well control
and by known continuity of hydrocarbon-saturated material above
known fluid contacts, if any, or above the lowest known structural
occurrence of hydrocarbons.
Developed - Reserves that are recoverable from existing
wells with current operating methods and expenses.
Developed reserves include both producing and nonproducing
reserves. Estimates of producing reserves assume recovery by
existing wells producing from present completion intervals with
normal operating methods and expenses. Developed nonproducing
reserves are in reservoirs behind the casing or at minor depths
below the producing zone and are considered proved by production
from other wells in the field, by successful drill-stem tests,
or by core analyses from the particular zones. Nonproducing
reserves require only moderate expense to be brought into
production.
Undeveloped - Reserves that are recoverable from additional wells
yet to be drilled.
Undeveloped reserves are those considered proved for production
by reasonable geological interpretation of adequate subsurface
control in reservoirs that are producing or proved by other wells
but are not recoverable from existing wells. This classification
of reserves requires drilling of additional wells, major deepening
of existing wells, or installation of enhanced recovery or other
facilities.
Reserves recoverable by enhanced recovery methods, such as injection of
external fluids to provide energy not inherent in the reservoirs, may be
classified as proved developed or proved undeveloped reserves depending
upon the extent to which such enhanced recovery methods are in operation.
These reserves are considered to be proved only in cases where a successful
fluid-injection program is in operation, a pilot program indicates
successful fluid injection, or information is available concerning the
successful application of such methods in the same reservoir and it is
reasonably certain that the program will be implemented.
Nonhydrocarbon helium and carbon dioxide reserves were classified using the
same standards as those described in the foregoing definitions of petroleum
reserves. Because these two gases are mixed in and produced with the
natural gas reserves, the term gas as used herein applies to all three
gases, where appropriate, and the term natural gas is used to refer to
hydrocarbon gas.
Estimates of the net proved reserves of MESA Inc, as of December 31, 1995,
are as follows:
TOTAL PROVED RESERVES
Natural Gas (MMcf)............ 1,218,029
Oil and Condensate (Mbbl)..... 9,521
Natural Gas Liquids (Mbbl).... 101,897
Helium (Mmcf)................. 3,670
Carbon Dioxide (Mmcf)......... 46,459
PROVED DEVELOPED RESERVES
Natural Gas (MMcf)............ 1,160,751
Oil and Condensate (Mbbl)..... 8,138
Natural Gas Liquids (Mbbl).... 97,060
Helium (MMcf)................. 3,630
Carbon Dioxide (MMcf) 16,308
Significant proved natural gas liquids reserves and helium reserves are
included herein for the Satanta plant in the Hugoton field in Kansas.
Proved helium reserves also are included for a helium recovery unit at the
Fain gas processing plant in the Panhandle field in Texas. Changes in
Hugoton field reserves reflect MESA's practice of recovering ethane at the
Satanta Plant. In previous years Hugoton proved reserve estimates were
prepared assuming that MESA would not recover ethane which resulted in
slightly higher natural gas volumes and lower natural gas liquids volumes.
The decision as to whether or not to recover ethane is economic and based
on the relative value of ethane as a liquid versus the energy-equivalent
value of such ethane if left in the residue natural gas. In the future, if
economic conditions warrant, MESA may revise proved reserves to reflect any
changes in such relative values.
The KCC held hearings from August 1992 to September 1993 to consider
changes to the methods in which fieldwide allowables are allocated among
individual wells within the Hugoton field. Specifically, the KCC
considered proposals from various producers to amend calculations of well
deliverability, the allocation of allowables for infilled units, and the
make up of underages from prior periods. On February 2, 1994, the KCC
issued an order, effective as of April 1, 1994, establishing new field
rules which modify the formulas and calculations used to allocate
allowables among wells in the field. The standard pressure used in each
wells' calculated deliverability was reduced by 35%, greatly benefitting
MESA Inc. high deliverability wells. Also, the new rules assign a 30%
greater allowable to 640-acre units with infill wells than similar units
without infill wells. Essentially all of MESA Inc. Hugoton infill wells
have been drilled, resulting in an increase to MESA Inc. in assigned
allowables beginning in April, 1994. The new field rules also allow
Hugoton producers to make up pre-1994 canceled underages over a 10-year
period.
MESA Inc. is continuing to upgrade the well-gathering system, which
improves deliverability of the wells. This increase in deliverability and
the associated costs have been incorporated in the estimates included
herein.
With the exception of a few properties in this report known as the "Texas
Panhandle - Other," the West Panhandle field properties are subject to an
operating agreement with Colorado Interstate Gas Company, hereinafter
referred to as "CIG." The properties subject to this agreement are
collectively referred to as the "B" Contract area. MESA Inc.'s share of
the "B" Contract area gas is processed through MESA Inc.'s Fain gasoline
plant in Potter County, Texas, and is subject to special royalty payments.
An agreement effective January 1, 1991, allocates 77 percent of the
remaining production from the "B" Contract properties to MESA Inc. and the
remaining 23 percent to CIG. CIG receives a 20-percent overriding royalty
interest on MESA Inc.'s share of the helium produced at this plant.
Agreements reached by MESA Inc. and CIG during 1993 provide that MESA Inc.
is entitled to a maximum of 32 Bcf at the Fain plant inlet for each of the
years 1994, 1995, and 1996, with CIG having the rights to the remainder of
the "B" Contract production in these years. CIG is entitled to a maximum
of 8.5 Bcf for each of the years 1997, 1998, and 1999, with MESA Inc. being
entitled to take the rest of the "B" Contract production in these years.
CIG's maximum take for the year 2000 is 7.56 Bcf, with a maximum of 7.0 Bcf
in years thereafter, until it has produced the full 23 percent of the
January 1, 1991, reserves to which it is entitled. In addition to its gas
take limitations, CIG has the right to take gas for use as field fuel until
July 2000. The projected volumes in this report assume that MESA Inc. will
take the maximum volume to which it is entitled under the contract, for as
long as the projection of allowables and deliverability will permit, after
which the projected deliverability is used. MESA Inc. can sell its share
of the "B" Contract gas to markets anywhere, whether inside or outside of
the City of Amarillo or inside or outside of the State of Texas. MESA
actual takes were 31 Bcf in 1994, and 29 Bcf in 1995. Takes were lower in
1995 due to weather related demand.
Since January 1, 1991, CIG has overproduced its 23 percent share of the
gas. This overproduction of gas by CIG and the subsequent gas balancing
has been accounted for in this report by adjusting MESA Inc.'s gas
interests in the "B" Contract Area over time. For accounting purposes, the
CIG gas imbalance discussed above is treated as production
income to MESA Inc. at the time CIG produced the gas; this revenue is then
recorded as an account receivable from CIG. This difference in treatment
must be considered when using this report with the accounting records. The
cumulative gas imbalance as of December 31, 1995 is tabulated below. These
amounts have not been deducted from this report.
Net Salable Gas, Mcf.............. 15,887,261
Net Natural Gas Liquids, Bbl...... 2,275,114
Net Condensate, Bbl............... 30,138
Net Helium, Mcf................... 75,069
Under a workover plan in the "B" Contract Area, approximately 357 wells
were worked over, deepened, or redrilled during the past six years. The
workover plan, a continuing project, is reevaluated each year to determine
the following year's work. This report includes proved reserves to be
developed over the next three years from zones below current completions in
66 wells. Also, MESA has added 10 development field extension wells in the
shallower West Panhandle (Red Cave) field which will be developed during
1996. MESA Inc. expects that numerous compressors will be installed on the
gathering system for this field near the wellheads to improve gas
deliverability. Approximately 155 compressors are currently installed and
we have assumed that 150 compressors will be installed during the next
three years.
The expected acceleration of production from these programs has been
incorporated in the estimated production rates. The expense of these
programs initially will be paid by CIG but will be repaid by MESA Inc. As
provided by the operating agreement between MESA Inc. and CIG, this
repayment has been amortized herein over the remaining lives of the
properties on a unit-of-production basis.
Future oil and gas producing rates estimated for this report are based on
production rates considering the most recent figures available. The rates
used for future production are rates that are believed to be within the
capacity of the well or reservoir to produce. Information on proration of
gas production has been considered in arriving at the rates projected.
Gas volumes are expressed at a temperature of 60 degrees Fahrenheit and at
the legal pressure base of the states in which the gas reserves are
located. Gross volumes are reported as wet gas and the net volumes are
reported as salable gas; however, neither the gross nor net volumes were
reduced for plant fuel usage, which is estimated to be 43.7 billion cubic
feet of gross wet gas. The value of this fuel is deducted as part of the
plant operating costs. Condensate reserves estimated herein are those to
be obtained by conventional lease separation.
Revenue values in this report were estimated using current prices and
costs. Future prices were estimated using guidelines established by the
Securities and Exchange Commission and the Financial Accounting Standards
Board. The initial and future prices and producing rates used in this
report are those that MESA Inc. can reasonably expect to be received over
the life of the properties. The assumptions used for estimating future
prices and costs are as follows:
Oil and Condensate Prices
- -------------------------
Oil and condensate prices were held constant for the life of the
properties.
Natural Gas, Helium, and Carbon Dioxide Prices
- ----------------------------------------------
Natural gas prices were held constant for the life of the properties except
for some 75 percent of the gas in the Texas Panhandle field.
Under existing contractual arrangements in the Panhandle properties, about
75 percent of the total gas is sold to Energas under a long-term contract.
In 1992, MESA Inc. and Energas negotiated a new pricing formula for the
next five years of gas sales to Energas. Seventy percent of the gas sold
to Energas will be sold at a fixed price that escalates by a total of $0.75
per thousand cubic feet from 1993 to 1997. The remaining 30 percent of
such gas will be sold at the "spot-market" gas price plus $0.10 per
thousand cubic feet. The pricing formula will be renegotiated for periods
after 1997. In this report, the prices applicable under the current
contract pricing formula were used through 1997. Beginning in 1998, the
1996 weighted average price was applied to the subsequent Energas sales.
Helium and carbon dioxide prices were held constant for the life of the
properties.
Natural Gas Liquids Prices
- --------------------------
Natural gas liquids prices were held constant for the life of the
properties.
Operating and Capital Costs
- ---------------------------
Estimates of operating costs based on current costs were used for the life
of the properties with no increases in the future based on inflation.
Future capital expenditures were estimated using 1995 values and were not
adjusted for inflation.
Oil and condensate production taxes were calculated using net removal
prices after deducting transportation charges.
Economic estimates were made, as of December 31, 1995, under the
aforementioned assumptions concerning future prices and costs and are
summarized as follows:
Future Gross Revenue (M$)........... 3,804,371
Production Taxes (M$)............... (100,230)
Ad Valorem Taxes (M$)............... (192,035)
Operating Costs (M$)................ (965,692)
Capital Costs (M$).................. (96,594)
Future Net Revenue (M$)(1).......... 2,449,820
Present Worth at 10 Percent (M$)(1). 1,040,413
(1) Future income tax expenses were not taken into account in
the preparation of these estimates.
Included above is revenue from nonhydrocarbon reserves (helium and carbon
dioxide) that will be produced with and separated from certain natural gas
as it is produced. It is estimated that about 3 percent of the present
worth shown above is attributable to this planned helium and carbon dioxide
recovery.
The information relating to estimated proved reserves, estimated future net
revenue from proved reserves, and present worth of estimated future net
revenue from proved reserves of oil, condensate, natural gas liquids, and
gas contained in this report has been prepared in accordance with
Paragraphs 10-13, 15 and 30(a)-(b) of Statement of Financial Accounting
Standards No. 69 (November 1982) of the Financial Accounting Standards
Board and Rules 4-10(a)(1)-(13) of Regulation S-X and Rule 302(b) of
Regulation S-K of the Securities and Exchange Commission; provided,
however, certain estimated data have not been provided with respect to
changes in reserve information, (i) future income tax expenses have not
been taken into account in estimating the future net revenue and present
worth values set forth herein, and (ii) minor amounts of revenue from
nonhydrocarbon gases are included herein.
To the extent the above-enumerated rules, regulations, and statements
require determinations of an accounting or legal nature or information
beyond the scope of this report, MESA Inc. is necessarily unable to express
an opinion as to whether the above-described information is in accordance
therewith or sufficient therefor.
Submitted,
/s/ Dennis E. Fagerstone
- ------------------------------------------
Dennis E. Fagerstone
Vice President-Exploration and Production
Signed: /s/ Dennis E. Fagerstone
---------------------------------
OPERATING AGREEMENT
This OPERATING AGREEMENT is made and entered into this 8th day of
January, 1988, to be effective as of January 1, 1990, by and between MESA
OPERATING LIMITED PARTNERSHIP, a limited partnership organized under the
laws of the State of Delaware with its principal place of business in
Amarillo, Texas (hereinafter referred to as "Mesa" or as "Operator"), and
COLORADO INTERSTATE GAS COMPANY, a corporation organized under the laws of
the State of Delaware with its principal place of business in Colorado
Springs, Colorado (hereinafter referred to as "CIG").
W I T N E S S E T H:
-------------------
WHEREAS, Mesa and CIG are the current parties in interest to an
agreement, as amended and supplemented, initially entered on January 3,
1928, between Canadian River Gas Company and Amarillo Oil Company, which
agreement is commonly referred to as the "B" Contract; and
WHEREAS, disputes arose between Mesa and CIG regarding their
respective actions under the "B" Contract which resulted in the filing of
lawsuits in Texas and Colorado; and
WHEREAS, Mesa and CIG have resolved such disputes, dismissed their
pending lawsuits and established a framework for future operations in an
Agreement of Compromise and Settlement (the "Settlement Agreement") dated
June 1, 1987; and
WHEREAS, such Settlement Agreement provided in part that on January 1,
1990, Mesa should become operator of the wells subject to the "B" Contract,
and further required the parties to enter into good faith negotiations and
reach agreement as to the terms and conditions of an operating agreement to
be effective January 1, 1990.
NOW, THEREFORE, it is agreed as follows:
ARTICLE I
Definitions
As used in this Operating Agreement, the following words and terms
shall have the following meanings:
"Acidize" shall mean a technique for increasing the production
from a well by introducing acid into the well under pressure in
order to enlarge and reopen pores in producing formations.
"Administrative Fee" shall mean the payments and charges which
CIG will be authorized to charge and collect from Mesa.
"AFE" shall mean an authorization for expenditure.
"British Thermal Unit" means the amount of heat required to
raise the temperature of one pound of water one degree
Fahrenheit at 60 degrees Fahrenheit.
"CIG" shall mean Colorado Interstate Gas Company and/or its
successor in interest under the "B" Contract.
"Contract Area" shall mean all of the Gas Leases (as defined
below) intended to be operated for gas purposes under this
Operating Agreement.
"Exploratory Well" shall mean a well drilled to test a
geologic zone or formation the depth of which is below
mean sea level
"Frac" shall mean an operation designed to crack or break
up formations which contain oil and gas by pumping liquids
and/or gases with proppants into the formation under high
pressure, in order to increase the formation's permeability
and to achieve greater production.
"FERC" means the Federal Energy Regulatory Commission, and
any successor agency.
"Gas" shall mean natural gas and all other gaseous
hydrocarbons produced therewith.
"Gross Heating Value," when applied to a cubic foot of gas,
means the number of British thermal units produced by
combustion, at a constant pressure, of the amount of gas
which would occupy a volume of one cubic foot at a temperature
of 60 degrees Fahrenheit if saturated with water vapor and
under a pressure equivalent to that of 30 inches of mercury at
32 degrees Fahrenheit and under standard gravitational force
(980.665 c.m. per sec.) with air of the same temperature and
pressure as the gas, when the products of combustion are cooled
to the initial temperature of gas and air and when the water
formed by combustion is condensed to the liquid state.
"Lease" or "Gas Lease" shall mean any one or more of the gas
leases now or hereafter subject to the "B" Contract on which
one or more of the wells listed and described on Exhibit "A"
hereto are located, or which are included in the proration
unit for any such well or wells.
"Mesa" shall mean Mesa Operating Limited Partnership and/or
its successor in interest under the "B" Contract.
"Operations and Maintenance Fee" shall mean the charges which
Mesa will be authorized to charge and collect from CIG for
performance of its duties as Operator under this Operating
Agreement.
"Proration Unit" shall mean the acreage assigned to a well
for the purpose of allocating allowable gas production thereto
by order or rule of the Texas Railroad Commission, or any
other state or federal body having authority.
"Replacement Well" shall mean any gas well drilled on a Gas
Lease subject to this Operating Agreement to replace an
existing gas well which is accepted by the Railroad Commission
of Texas as a replacement for such well.
"Rework" means an operation performed on a well after it has
been completed in an effort to secure production where there
has been none, to restore production that has ceased, or to
increase production. Cleaning out a well bore that has silted
up is a typical Rework operation. Deepening or Side Tracking
will be treated as an "Exploratory Well" if the objective depth
of said well satisfies the definition of Exploration Well
contained in Article I. Depending on the context, the term
Rework may also include Acidizing or a Frac.
"Side Tracking" means a drilling operation involving the use
of a portion of an existing well bore to drill a second hole,
resulting in a well that is partly old and partly new. Such an
operation will be treated hereunder as an "Exploratory Well" if
the objective depth of said well satisfies the definition for
Exploratory Well contained in Article I.
ARTICLE II
Exhibits
The following exhibits, as indicated below and attached hereto, are
incorporated in and made a part of this Operating Agreement:
EXHIBIT Description
"A" is a list of all wells on the Contract Area in which CIG has a
working interest, their location, CIG's meter number, and
CIG's working interest therein.
"B" is a list of other operating agreements to which CIG is a
party which affect wells on the Contract Area.
"C" is the accounting procedure to be used by the parties hereto
for the purposes hereof.
"D" is a list of the insurance requirements.
"E" is the Non-Discrimination and Certification of Non-Segregated
facilities.
ARTICLE III
Interests of the Parties
3.1 Ownership: Exhibit "A" lists the fractional working interest of
---------
CIG in existing gas wells on the Gas Leases covered by this Operating
Agreement. Except as provided elsewhere herein, all equipment and all
material acquired for operations on such wells, or on any additional gas
wells drilled on the Gas Leases during the term of this Operating Agreement
shall be owned by CIG to the full extent of its interest in such well (or
to the extent of CIG's interest in the proration unit for such well, as the
case may be).
3.2 Allocation of Costs: Except as provided elsewhere herein, all
-------------------
costs and expenses incurred in operations under this Operating Agreement
will be borne and paid by the parties hereto as provided in the accounting
procedure attached as Exhibit "C."
3.3 Subsequently Created Interests: Neither party hereto shall create
------------------------------
any additional overriding royalty, production payment or other burden
payable out of production attributable to the Gas Leases subject to this
Operating Agreement without the prior written consent of the other party
hereto; provided, however, that CIG reserves the right in its sole
discretion to negotiate and settle disputes with its royalty owners.
However, subsequent to that point in time when CIG does not take delivery
of at least two (2) BCF of gas for the immediately preceding twelve (12)
month period pursuant to the terms and conditions of the "B" Contract, as
amended, CIG shall not enter into a settlement with any of its royalty
owners that would or may have the effect of reducing or diminishing Mesa's
rights or benefits (including any adverse economic impact to Mesa) under
the "B" Contract and to the delivery of gas volumes pursuant to the "B"
Contract without first obtaining Mesa's prior written consent.
ARTICLE IV
Operator
4.1 Designation and Responsibilities of Operator: Mesa shall become
Operator of the existing gas wells on the Gas Leases subject to this
Operating Agreement, and of any additional gas wells drilled on the
Contract Area on January 1, 1990, and shall operate and maintain the well
bores, wellhead and surface equipment of such wells. Mesa's authority and
responsibility for such wells shall extend and be limited to operations up
to the check valve downstream of the side valve (i.e., up to the inlet of
CIG's metering facility) on the wellhead of such wells which do not have
surface production equipment, and to the first check valve downstream of
surface production equipment (i.e., up to the inlet of CIG's metering
facility) on wells having pumps, tanks or other such surface production
equipment. As so limited, Mesa shall conduct, direct and have full control
of the operation of, and of the maintenance operations on, such wells
thereafter as permitted and required by, and within the limits of, this
Operating Agreement.
4.1.1 As soon as practical after signing this Operating Agreement,
CIG shall deliver copies or make available to Mesa at CIG's office all of
CIG's original well, geological, production and seismic files and records
concerning CIG's wells on the Contract Area and any related production
information requested by Mesa.
4.2.2 Mesa shall cooperate fully with CIG to ensure that CIG is able
to fulfill its obligations under various agreements and other instruments
involving the West Panhandle Field including but not limited to:
That certain Agreement dated July 1, 1967, by and between The
Capital National Bank, Austin, Texas, as Trustee for Mary Lewis
Scott Kleberg Trusts Nos. 1, 2 and 3, et al., and CIG; and
-----
That certain Operating Agreement dated August 18, 1949, between
Mary E. Bivins, et al., and CIG.
-----
In addition, Mesa shall administer (and, if necessary, serve as "operator"
under) the other operating agreements listed on Exhibit "B" hereto which
affect wells on the Contract Area, and CIG will execute any forms required
by the Texas Railroad Commission necessary to effectuate the change of
operator under this Operating Agreement and under the operating agreements
listed in Exhibit "B".
4.1.3 In performance of its obligations hereunder, Mesa shall be held
to the standard of a reasonably prudent operator, giving consideration to
the needs and interests of both parties hereto. Mesa shall operate the
wells on the Contract Area in accordance with prudent operating practice,
and Mesa shall be solely responsible for all operational means, methods,
techniques, procedures and coordination of its operations hereunder.
4.1.4 Mesa shall take all steps reasonably necessary to maintain and
improve the gas deliverability from the wells on the Contract Area at or
near their maximum potential in light of their respective degrees of
depletion and of other mechanical and operating conditions.
4.1.5 Mesa shall obtain all necessary permits and licenses which are
required by the state, county, city or other political subdivision, or any
other duly constituted public authority for operations hereunder on wells
on the Contract Area.
4.1.6 Mesa shall have the right to install standard mechanical
separators at or near all well(s) and all separated liquids, if any and in
whatever volume, shall be owned in accordance with the "B" Contract, as
amended.
4.2 Removal of Operator: CIG may remove Mesa as Operator upon the
-------------------
occurrence of any one or more of the following circumstances:
(a) If Mesa becomes bankrupt or insolvent, or commits or
suffers any act of bankruptcy or insolvency, or makes
any assignment for the benefit of creditors;
(b) If Mesa, subject to 4.2(c) below, terminates its legal
existence, or is no longer capable of serving as Operator,
or if it fails or refuses to carry out its duties as
Operator hereunder; or
(c) If Mesa assigns or purports to assign its general powers
and responsibilities of supervision and management as
Operator hereunder, provided that a change of limited
partnership name or structure of Mesa, or the transfer
of Mesa's interest to any single subsidiary, affiliate
or successor (whether individual, corporate, general or
limited partnership) shall not be a basis for removal
of Mesa as Operator hereunder.
Mesa may resign as Operator at any time after January 1, 1990, on giving
CIG one hundred twenty (120) days' notice of its intention to resign.
4.3 Compensation: As compensation for the performance of its duties
------------
and responsibilities hereunder, Mesa shall be entitled to bill and to
collect from CIG an Operations and Maintenance Fee as provided in the
accounting procedure attached hereto as Exhibit "C."
4.4 Personnel: Mesa shall conduct its operations hereunder, or cause
---------
them to be conducted, in a skillful, thorough and workmanlike manner by
qualified, careful and efficient workers.
4.4.1 The number of employees used by Mesa in conducting operations
hereunder, their selection, and the hours of labor and the compensation for
services performed shall be determined solely by Mesa, and such employees
shall be the employees of Mesa.
4.4.2 Mesa shall give adequate personal supervision to the wells on
the Contract Area and to operations hereunder, and shall keep continuously
available a competent superintendent or foreman with authority to act for
Mesa.
4.4.3 Mesa shall be responsible for the acts and omissions of its
employees and subcontractors.
4.5 Drilling and Rework Contracts: All drilling or rework operations
-----------------------------
authorized in Article VI hereinbelow, shall be performed on a competitive
contract basis at the usual rates prevailing in the area. Mesa shall
request bids for all such operations, and shall have a service contract
with each contractor performing work on any well in the Contract Area;
provided, however, that Mesa shall have the right to reject the lowest bid
received for any such work and/or to negotiate changes in any such
agreements if in Mesa's sole judgment conditions warrant. If it desires,
Mesa may employ its own tools and equipment in the conduct of operations on
wells on the Contract Area, but its charges therefor shall not exceed the
prevailing rates in the area. The rate of such charges shall be agreed
upon by the parties in writing before drilling or reworking operations are
commenced, and such work shall be performed by Mesa under the same terms
and conditions as are customary and usual in the area in contracts of
independent contractors who are doing work of a similar nature.
4.6 Liens: Mesa shall take all reasonable measures to keep the Gas
-----
Leases subject to this Operating Agreement free and clear of all liens,
claims and encumbrances arising from the performance of operations
hereunder either by Mesa or by any of Mesa's contractors or subcontractors.
4.7 Books and Records: Mesa shall keep records and books of account,
-----------------
which shall be subject to audit by CIG (as provided in paragraph 1.5 of the
accounting procedure attached hereto as Exhibit "C") showing the actual
cost to Mesa of all items of labor, materials, equipment, supplies,
services and all other expenditures of whatever nature for which payment is
authorized under the provisions of this Operating Agreement, and of the
number of employees used by Mesa for performance of its duties hereunder,
their selection, and the hours of labor and the compensation for their
services.
4.8 Production and Operations Records: Mesa shall keep production
---------------------------------
and operations records including, but not by way of limitation, blow
tickets, unofficial tests, tank gauges and well inspection reports, which
shall be subject to inspection by CIG at Mea's offices during normal
business hours upon reasonable request and at mutually convenient times.
ARTICLE V
Gas Gathering, Payments, Metering and Tests
5.1 Delivery of Production: Subject to the other provisions hereof,
----------------------
Mesa shall deliver to CIG, and CIG will receive all gas produced from wells
on the Contract Area.
5.1.1 CIG shall not deny Mesa the right to deliver "B" Contract gas
from wells on the Contract Area into the CIG gathering system; provided,
however, that CIG shall not be required to install facilities to take gas
from wells which cannot be economically produced into CIG's existing
facilities.
5.1.2 For delivery of gas hereunder Mesa shall use existing points of
delivery on CIG's gathering system and any additional points as may be
agreed to from time to time.
5.1.3 Mesa shall not, without CIG's prior consent, attempt to deliver
gas through any such delivery points in quantities which interfere with
other uses of the gathering system or which exceed CIG's ability to
transport gas in the system from the field. In the event CIG is not a
participant in a well or CIG's rights to its portion of "B" Contract gas
terminates, CIG agrees that it shall not deny Mesa the right to deliver all
of its "B" Contract gas to and utilize CIG's gathering system or facility.
5.1.4 Gas shall be delivered hereunder at each such point of delivery
at pressure sufficient to enter the CIG gathering system against the
pressure existing therein from time to time; provided, however, that CIG
shall not be required in any event to reduce its line pressure below
thirty-five (35) pounds per square inch gauge. Mesa shall not, under any
circumstances, have any obligation to install compression facilities at any
particular well or wells; provided, however, that Mesa shall have the right
to install any compression or other facility which a reasonably prudent
operator would install under the same or similar circumstances.
5.1.5 For the purpose of measurement, the average absolute
atmospheric (barometric) pressure shall be assumed to be 13.2 pounds per
square inch, irrespective of the actual elevation or location of the
delivery points above sea level or of variation in such barometric pressure
from time to time.
5.1.6 Gas delivered hereunder shall be gas as delivered in its
natural state from the wells, or compressors, including hydrocarbon and
nonhydrocarbon substances in a vaporous state. Gas shall be commercial in
quality and be reasonably free from any foreign materials such as dirt,
dust, iron particles and other similar matter. It shall be reasonably free
from objectionable liquids; and it shall contain no more than seven (7)
pounds of water in the vapor phase per million cubic feet. It will be
delivered at a temperature sufficient to prevent freezing in the gathering
system, but in no event shall the gas exceed a temperature of 120 degrees
Fahrenheit at the point of delivery. However, and notwithstanding anything
in this Operating Agreement to the contrary, Mesa shall have no obligation
to install dehydration or other facilities or perform any other operation
to dehydrate or treat gas delivered to CIG's gathering facility.
5.2 Nominations: Gas nominations required by the Texas Railroad
-----------
Commission under 16 TAC Section 30 shall be handled as follows:
5.2.1 CIG shall continue to make the pipeline nominations as the
initial nominator.
5.2.2 CIG shall provide Mesa with its nomination for production in
the month preceding the month in which such production is to occur, and
Mesa shall make the producer nomination.
5.3 Scheduling: The dispatching of gas to be delivered hereunder to
----------
CIG shall be handled as follows:
5.3.1 In addition to the written nominations described in section 5.1
above, CIG shall give Mesa more frequent periodic nominations by telephone;
and subject to compliance with any valid orders of the Texas Railroad
Commission to restrict or curtail production from such wells, Mesa in the
good-faith exercise of its obligations as a prudent operator, will give
reasonable consideration to such nominations and CIG's well scheduling
requests.
5.3.2 By the 15th of each month preceding the month in which
scheduled deliveries are to occur, Mesa shall prepare and deliver to CIG a
"well schedule" showing Mesa's proposed allocation of production among the
wells subject to this Operating Agreement.
5.3.3 CIG shall operate its gathering system during the succeeding
month using such well schedule as a guide subject, however, to regulatory
or operational constraints and requirements and daily fluctuations in
demand; and CIG agrees to cooperate with Mesa in the operation of the
gathering system in order to avoid, to the extent reasonably possible, any
unnecessary shutting-in or curtailment of wells delivering gas from the
Contract Area.
5.3.4 Either party may at any time request a change in the monthly
well schedule. Notwithstanding Article XV hereinbelow, Mesa and CIG will
cooperate in carrying out the necessary scheduling including, if needed,
the holding of ad hoc meetings. Any such meeting may be called by either
party hereto by the furnishing of a meeting agenda to the other party at
least ten (10) days prior to the date scheduled for such meeting. The site
of such meetings shall alternate between the offices of the parties unless
otherwise required by the subject matter of the meeting, e.g., a meeting
involving an inspection of the wells would not normally be held in
Colorado.
5.4 Rents and Royalties: As the owner of the production facilities
--------------------
from which gas from wells on the Contract Area is delivered, CIG shall
perform the following operations:
5.4.1 CIG shall pay or deliver, or cause to be paid or delivered, all
leasehold royalties, overriding royalties and other payments out of
production which are due on gas produced from wells on the Contract Area
and delivered into its gathering system.
5.4.2 All rentals, shut-in well payments and minimum royalties which
may be required under the terms of any Gas Lease subject to this Operating
Agreement shall be paid by CIG.
5.5 Taxes: CIG shall render and pay the following taxes:
-----
5.5.1 CIG shall render for ad valorem taxation all property subject
to this Operating Agreement which by law should be rendered for such taxes,
and it shall pay all such taxes assessed thereon before they become
delinquent. In the event that CIG considers any tax assessment to be
improper, CIG may, at its sole discretion, protest within the time and in
the manner prescribed by law, and prosecute its protest to a final
determination, or abandon the protest prior to final determination. During
the pendency of any such administrative or judicial proceeding, CIG may
elect to pay, under protest, all such taxes and any interest and penalty.
When any such protested assessment shall have been finally determined, CIG
shall pay the tax and any interest and penalty accrued.
5.5.2 CIG shall pay, or cause to be paid, all production, severance
and other taxes imposed upon or with respect to gas produced from the wells
on the Contract Area and delivered into its gathering system.
5.6 Gas metering: CIG shall meter the gas produced from the wells on
------------
the Contract Area and delivered into its gathering system; provided,
however, that Mesa shall have the right to set check meters upstream of
CIG's metering facilities.
5.7 Well Qualifications under the NGPA: CIG shall continue to file
-----------------------------------
the applications required by the Natural Gas Policy Act ("NGPA") for
determination of the well classification of all wells on the Contract Area
subject to this Operating Agreement. CIG shall also be responsible for
administering the Section 108 (Stripper) well classifications for any wells
which qualify until January 1, 1990. Thereafter, until the occurrence of
the Set Point Date (as defined in Article XIII), Mesa shall have the right
to jointly participate with CIG in the preparation, analysis and subsequent
filing of well qualifications filed under the NGPA. The parties agree to
cooperate fully in the reaching of mutual agreement as to the proper well
qualification selected; provided, however, if a dispute occurs, the parties
agree to utilize an independent consultant to make such determination with
such determination to be fully binding upon both CIG and Mesa. Upon the
occurrence of the Set Point Date, CIG agrees that the responsibilities and
functions contained within this paragraph 5.7 shall also be transferred
within sixty (60) days to Mesa pursuant to the same standards of
performance applicable to the other transferred responsibilities set forth
in paragraph 13.2.2 hereinbelow.
5.8 Well Testing: CIG shall annually test, or cause to be tested, all
-------------
gas wells on the Contract Area as required by the Texas Railroad
Commission, and shall file any forms required by such activities, in
accordance with the following procedures:
5.8.1 CIG shall provide Mesa a written testing schedule at least
twenty (20) days prior to the commencement of such tests, and Mesa shall
have the right to have a representative present during all phases of the
well test, to meter any gas and to take any samples which it may desire.
CIG shall conduct all tests in accordance with customary and usual
standards for testing operations normally expected of a reasonable prudent
operator of wells in the Texas West Panhandle and Texas West Panhandle (Red
Cave) fields.
5.8.2 The wells shall be tested in groups behind a field compressor
with the cooperation of CIG's gathering system so as to maximize the
producing ability of the individual wells during the test.
5.8.3 Each well shall be flowed at its maximum allowable rate on the
test to avoid any reduction in allowable which could result from the use of
a reduced rate during the test.
5.8.4 CIG and Mesa shall jointly interpret all such test data and CIG
shall prepare the appropriate Railroad Commission form(s) for Mesa's
execution and filing with the Commission. In the event, for whatever
reason, Mesa and CIG are unable to agree on an interpretation of the test
data pertaining to any well or wells, then Mesa shall engage the services
of THURMOND-MCGLOTHLIN, Inc., 921 West Harvester, Pampa, Texas (or, in the
event such firm is unavailable, another mutually agreeable and competent
reservoir engineering company) for the purpose of making an independent
interpretation of such test data. Mesa shall then prepare and file the
appropriate form(s) with the Railroad Commission using the consultant's
interpretation of the test data. The fees for any such services shall be
an Allowable Cost charged and shared as provided in the accounting
procedure attached hereto as Exhibit "C".
5.8.5 Notwithstanding the provision of paragraph 5.8.4 above, in the
event disagreement as to the interpretation of test data does occur, and
such disagreement rests upon the good faith belief by either party that the
test data is unreliable or inaccurate, then in such event either party may
request a retest of the well by CIG, and such retest will be conducted
within thirty (30) days of such request in accordance with all other
procedures set forth above.
5.8.6 Mesa shall also keep CIG apprised of any and all material
communications with the Railroad Commission, and especially of any requests
for retesting of any well which may be received from the Commission.
5.8.7 CIG will also furnish Mesa with copies of all information and
reports related to its tests of the wells on the Contract Area.
5.9 Compensation: CIG shall be entitled to bill and to collect an
-------------
Administrative Fee as specified in the accounting procedure attached hereto
as Exhibit "C".
5.10 Personnel: The number of employees used by CIG for performance
----------
of its duties hereunder, their selection, and the hours of labor and the
compensation for their services shall be determined by CIG, and all such
employees shall be the employees of CIG.
5.11 Books and Records: CIG will keep records and books of account,
------------------
which shall be subject to audit as provided in paragraph 1.5 of the
accounting procedure attached hereto as Exhibit "C" showing the
expenditures and payments authorized to be made by CIG pursuant to the
provisions of this Operating Agreement, if any, and the number of employees
used by CIG in the performance of its duties hereunder, their selection,
and the hours of labor and the compensation for their services.
<PAGE>
ARTICLE VI
Drilling and Reworks
6.1 Reworks and Redrills: Prior to that point in time when CIG does
---------------------
not take delivery of at least two (2) BCF of gas for the immediately
preceding, twelve (12) month period pursuant to the terms and conditions of
the "B" Contract, as amended, either party hereto may at any time and from
time to time, propose to Rework or otherwise repair, to deepen or Side
Track into a zone or formation the depth of which is above mean sea level,
to Acidize, to "Frac" or otherwise stimulate, or to plug back any dry hole
or existing well on the Contract Area, or to drill a Replacement Well by
giving the other party written notice of the proposed operation specifying
the work to be performed, the location, proposed depth of completion and
the objective formation. In the event a proposal is made as described
herein, it is stipulated that neither party shall have any right not to
participate in such proposal. Subsequent to that point in time when CIG
does not take delivery of at least two (2) BCF of gas for the immediately
preceding twelve (12) month period pursuant to the terms and conditions of
the "B" Contract, as amended, and for all periods subsequent thereto, CIG
shall no longer have the right to submit any further proposals and/or AFE's
to Mesa. Notwithstanding the above provisions, CIG and Mesa stipulate and
agree that nothing herein contained shall in any way modify, change or
otherwise diminish CIG's right to take delivery of gas pursuant to the "B"
Contract, as amended.
6.1.1 If Mesa makes any such proposal, it shall accompany the
proposal with an AFE specifying the work to be performed and the estimated
cost of the operation. If the proposal is made by CIG, Mesa shall have
thirty (30) days in which to prepare and submit such an AFE to CIG.
Provided, however, that in either event, if drilling or reworking equipment
is on location, CIG may waive preparation of an AFE and request that the
operation commence immediately. CIG reserves the right to contest the
reasonableness and amount of costs incurred in any such project,
notwithstanding the receipt and acceptance of an AFE and completion of the
project.
6.1.2 Mesa shall, within ninety (90) days after work is proposed,
actually commence the proposed operation and complete it with due diligence
at the cost and expense of CIG, as a Capital Expenditure as set forth in
the accounting procedure attached as Exhibit "C". If Mesa has not
commenced the actual operation within the time provided and further fails
to do so within thirty (30) days of receipt of written demand from CIG
following such period for performance of the operation, CIG may elect to
have the operation performed by an independent contractor.
6.2 Exploratory Drilling: Beginning on January 1, 1990, Mesa shall
---------------------
have the exclusive right at any time and from time to time, to conduct the
drilling of Exploratory Wells, or to conduct the deepening (or Side
Tracking) of existing wells not then producing in paying quantities, into
geologic formations the depths of which are below mean sea level. Mesa
shall nevertheless give CIG written notice at least two weeks in advance of
the commencement of any such operation specifying the nature of the
operation, the location, proposed depth and objective formation.
6.2.1 The cost and expense of any such operation which is drilled and
completed, or abandoned, into a formation the depth of which is below mean
sea level will not be treated as a Capital Expenditure (as otherwise
provided in paragraph 6.1.2 for Reworks and Redrills). The costs,
liabilities and expenses of any such operation shall be borne entirely by
Mesa, and Mesa shall receive all gas produced from any such completion
subject to the terms and provisions of the "B" Contract.
6.2.2 Any such operation which is plugged back and completed in a
formation the depth of which is above mean sea level shall be regarded as a
Rework or Redrill, and the cost and expense of the completion operation
following the plugging back of the well shall be treated as a Capital
Expenditure as provided in subparagraph 6.1.2 above. All other costs,
liabilities and expenses involved in the drilling of the test, in the
abandonment of the bottom of the well bore, and of plugging back shall be
borne entirely by Mesa. Provided, however, that all mutually agreeable
costs and expenses incurred from the surface down to that depth at which
completion of the plugback was accomplished shall be deemed a Capital
Expenditure to be accounted for pursuant to the provisions of the attached
Exhibit "C".
6.3 Access to Wells and Information: CIG shall have access to the
--------------------------------
drillsite of any well where an operation is in progress at all reasonable
times, at its sole cost, risk, and expense to inspect or observe
operations, and shall have access during working hours to information
pertaining thereto.
6.4 Abandonment of Wells: No well shall be plugged and abandoned by
---------------------
Mesa without mutual consent. The cost and expense of such operation shall
be considered an Allowable Cost for purposes of the accounting procedure
attached hereto as Exhibit "C" and included in computation of the
Operations and Maintenance Fee.
ARTICLE VII
Expenditures and Liabilities of the Parties
7.1 Liability of the Parties: Liability of Mesa and CIG shall be
-------------------------
several, not joint or collective. Each party shall be responsible only for
its obligations and shall be liable only for its proportionate share of the
Operations and Maintenance Fee and of the Administrative Fee, as set forth
in the accounting procedure attached hereto as Exhibit "C." It is not the
intention of the parties to create, nor shall this Operating Agreement be
construed as creating, a joint venture, mining or other partnership or
association, or to render the parties liable as partners.
7.2 Payments and Accounting: Except as herein otherwise specifically
-----------------------
provided, Mesa shall promptly pay and discharge expenses incurred in its
operations on the wells on the Contract Area, and shall charge CIG with its
share of Allowable Costs as provided in the accounting procedure attached
hereto as Exhibit "C".
7.3 Limitation on Expenditures: Except as otherwise provided in
---------------------------
paragraph 6.1 hereof, without prior written consent of CIG, Mesa shall
undertake no single project reasonably estimated to require an expenditure
in excess of $25,000; provided, however, that in case of explosion, fire,
flood, or other sudden emergency, whether of the same or different nature,
Mesa may take such steps and incur such expenses as in its opinion are
required to deal with the emergency to safeguard life and property. In the
event of any such emergency, Mesa shall as promptly as possible report the
emergency to CIG. In any event, if Mesa prepares an AFE for its own use
for any single project estimated to require an expenditure in excess of
$10,000, it shall furnish an informational copy of such AFE to CIG.
7.4 Insurance: At all times while operations are conducted hereunder,
----------
Mesa shall comply with the Workers' Compensation and Occupational Disease
Insurance including Employer's Liability Insurance covering its employees
engaged in operations hereunder in compliance with all applicable State
laws. Such policies shall contain underwriters waiver of subrogation in
favor of CIG. Mesa and CIG shall carry for their sole interest, but not
for the benefit nor cost of one another, insurance coverage as outlined in
Exhibit "D". Mesa shall require all contractors engaged in work on the
wells to comply with the applicable State laws and to maintain such other
insurances as Mesa may require.
ARTICLE VIII
Maintenance and Surrender of Leases
8.1 Right of First Refusal: Prior to its surrender to the Lessor, or
-----------------------
the Lessor's successors and assigns, of any interest in any lease, or in
any portion of a lease, subject to this Operating Agreement, and subject to
any other preferential rights in favor of third parties originating prior
to the effective date of this Operating Agreement, CIG shall first tender
the interest to be surrendered to Mesa; and if Mesa does not consent to the
surrender, CIG shall assign to Mesa, without warranty of title, express or
implied, subject to CIG's obtaining of any necessary regulatory approval,
all of CIG's interest in such lease, or portion thereof, and in any well,
material and equipment which may be located thereon together with all of
CIG's further rights to production therefrom. CIG shall not create any
rights as to the subject matter of this paragraph in favor of third parties
subsequent to May 29, 1987 (the date of the Settlement Agreement).
8.2 Effect of Assignment: Following such an assignment as described
---------------------
in paragraph 8.1, CIG shall be relieved from all obligations thereafter
accruing, but not theretofore accrued, with respect to the acreage assigned
and with respect to the operation of any well thereon; CIG shall have no
further interest in the lease assigned or in its equipment or production;
and the acreage assigned or surrendered, and subsequent operations thereon,
shall not thereafter be subject to the terms and provisions of this
Operating Agreement. Any assignment or surrender made under this provision
shall not reduce or change CIG's interest, as it was immediately before the
assignment, in the balance of the leases subject to this Operating
Agreement, or in the remaining wells subject to this Agreement on the
Contract Area.
8.3 Payment for Equipment: In connection with any such assignment as
----------------------
described in Paragraph 8.1, Mesa shall pay, subject to paragraph 6.4 to CIG
the remaining net book value of CIG's interest in any wells and in the
salvable casing, well and surface equipment on the assigned acreage.
ARTICLE IX
Internal Revenue Code Election
9.1 This Operating Agreement is not intended to create, nor shall it
be construed to create, a relationship of partnership or an association for
profit between or among the parties hereto. Notwithstanding any provision
herein that the rights and liabilities hereunder are several and not joint
or collective, or that this Operating Agreement and operations hereunder
shall not constitute a partnership, if, for Federal income tax purposes,
this Operating Agreement and/or the operations hereunder are regarded as a
partnership, each party hereto hereby elects to be excluded from
application of all provisions of Subchapter "K" of Chapter 1, Subtitle "A"
of the Internal Revenue Code of 1954 as permitted and authorized by Section
761 of the Code and the regulations promulgated thereunder. Operator is
hereby authorized and directed to execute on behalf of CIG such evidence of
this election, as may be required by the Secretary of the Treasury of the
United States or the Federal Internal Revenue Service, specifically
including, but not by way of limitation, all of the returns, statements,
and the data required by Federal Regulations 1.761. Should there be any
requirement that each party hereby affected give further evidence of this
election, each such party shall execute such documents and furnish such
other evidence as may be required by the Federal Internal Revenue Service
or as may be necessary to evidence this election. Neither party shall give
any notices or take any other action inconsistent with the election made
hereby.
9.2 If any present or future income tax laws of the State of Texas or
any future income tax laws of the United States contain provisions similar
to those in Subchapter "K", Chapter 1, Subtitle "A" of the Internal Revenue
Code of 1954, under which an election similar to that provided by Section
761 of the Code is permitted, each party hereto shall make such election as
may be permitted or required by such laws.
9.3 In making the foregoing election, each party hereby states and
agrees that the income derived by such party from operations hereunder can
be adequately determined without computation of partnership taxable income.
ARTICLE X
Claims and Lawsuits
10.1 Claims for Personal Injury or Property Damages: Mesa may settle
-----------------------------------------------
any third-party personal injury or property damage claim or suit arising
from or related to Mesa's operations hereunder subsequent to January 1,
1990 if the expenditure does not exceed Twenty-Five Thousand Dollars
($25,000) and if the payment is in complete settlement of such claim or
suit; provided, however, CIG's permission to settle shall not be required
in any claim or suit for which CIG would be indemnified pursuant to
paragraph 10.1.1. If the amount required for settlement exceeds the above
amount, Mesa shall immediately notify CIG. The costs and expenses of
handling, settling, or otherwise discharging such claim shall be allocated
in accordance with the following two paragraphs:
10.1.1 Mesa's Indemnity: Mesa agrees to protect, indemnify and hold
-----------------
harmless CIG, its officers, agents and employees from every kind and
character of damages, losses, expenses, demands, claims and causes of
action which arise from any cause growing out of or incident to operations
conducted by Mesa, its employees or by Mesa's contractors or subcontractors
under this Operating Agreement.
10.1.2 CIG's Indemnity: CIG agrees to protect, indemnify and
----------------
hold harmless Mesa, its officers, General Partner, agents and employees
from every kind and character of damages, losses, expenses, demands, claims
and causes of action which arise from any cause growing out of or incident
to operations conducted by or the actions of CIG, its employees or by CIG's
contractors or subcontractors under this Operating Agreement (including for
illustration and not limitation, well testing), or growing out of or
incident to CIG's operation of its gathering system.
10.2 Claims Concerning Royalty Payments: CIG may settle any
-----------------------------------
single third party claim or suit concerning the payment of royalty,
overriding royalty or other interest in production from wells on the
Contract Area arising out of CIG's payments with respect to production from
such wells if the expenditure does not exceed Twenty-Five Thousand Dollars
($25,000) and if the payment is in complete settlement of such claim or
suit. If the amount required for settlement exceeds such amount, CIG shall
immediately notify Mesa. Costs and expenses of handling, settling, or
otherwise discharging such claim or suit shall be allocated between the
parties based on their respective takes of the volume of gas produced on
which the claim for such underpayment is based. In the event that the
respective takes cannot be precisely determined, they shall be presumed to
be equal to the ratio of the total volumes delivered by CIG from the
gathering system to each party during the period in question, to the total
delivered by CIG to the parties during such period.
10.3 Claims or Lawsuits Concerning Drainage by Third Parties: Either
--------------------------------------------------------
Mesa or CIG may take action to defend the gas reserves in and under the Gas
Leases in the Contract Area from drainage by third parties, including, but
not by way of limitation, the reporting of improper activities to the Texas
Railroad Commission, and the filing of lawsuits; provided, however, that
neither Party hereto may be joined as a co-plaintiff in any such lawsuit
without its prior consent. The cost and expense of any such activities
shall be shared by Mesa and CIG on a sliding scale as follows: For any
actions taken in the first year (1990), Mesa shall bear 80% of the costs
and expenses and CIG 20%. For actions commenced in the second year, Mesa
shall bear 82% and CIG 18%, and for each year thereafter, Mesa's percentage
will continue to increase by two percent per year and CIG's percentage will
decrease by the same amount.
ARTICLE XI
Force Majeure
11.1 Suspension of Obligation to Perform: In the event that either
------------------------------------
party is rendered wholly or in part by force majeure unable to carry out
its obligations under this Operating Agreement other than to make payments
of amounts due thereunder, it is agreed that upon such party's giving
notice and full particulars of such force majeure in writing or by
telegraph to the other party as soon as possible after the occurrence of
the cause relied on, then the obligations of such party, insofar as they
are affected by such force majeure, shall be suspended during the
continuance of the disability so caused, but for no longer period. Any
such cause shall, so far as possible, be remedied with all reasonable
dispatch; provided, however, that this requirement of remedy with all
reasonable dispatch shall not require the settlement of strikes, lockouts,
or other labor difficulty by the party involved, contrary to its wishes and
the handling of any such difficulties shall be entirely within the
discretion of the party concerned.
11.2 Definition: The term "force majeure" as employed herein shall
mean acts of God, strikes, lockouts or other industrial disturbances, acts
of the public enemy, wars, blockades, insurrections, riots, epidemics,
landslides, lightning, earthquakes, fires, storms, floods, washouts, arrest
and restraint of rulers and peoples, civil disturbances, explosions,
breakage or accident to machinery or lines of pipe, freezing of wells or
lines of pipe, shutdowns for necessary maintenance, alterations or repairs,
sudden partial or sudden entire failure of wells, failure to obtain
materials and supplies due to governmental regulations, and causes of like
or similar kind, whether herein enumerated or not, and not within the
control of the party claiming suspension, and which by the exercise of due
diligence such party is unable to overcome.
ARTICLE XII
Notices
All notices or other communications required or permitted to be given
pursuant to this Agreement (other than nominations, which may be made by
telephone) shall be given in writing and shall be considered as properly
given or made if hand delivered, or telecopied, if mailed from within the
United States postage prepaid, or if telegraphed, by a prepaid telegram,
and addressed to the party to whom the notice is given as follows:
Colorado Interstate Gas Company
(telecopy) (719) 520-4317
(telephone) (719) 473-2300
2 North Nevada
P. 0. Box 1087
Colorado Springs, CO 80944
Mesa Operating Limited Partnership
(telecopy) (806) 378-1030
(telephone) (806) 378-1000
One Mesa Square
P. 0. Box 2009
Amarillo, TX 78189-2009
Either party may change its address by giving notice to the other.
ARTICLE XIII
Term of Agreement
13.1 Term: This Operating Agreement shall become effective January 1,
-----
1990, and shall remain in full force and effect as to the gas wells and
leases subject hereto, and as to operations thereon, for so long as any of
the leases now or hereafter subject to the "B" Contract, as amended, remain
in full force and effect unless cancelled by the mutual consent of the
parties prior to that time. It is agreed, however, that the termination of
this Agreement shall not relieve any party hereto from any liability which
has accrued or attached prior to the date of such termination. In the
event that Mesa resigns or is removed as Operator under the provisions of
this Agreement, Mesa and CIG agree to meet and discuss, if appropriate, the
amendment or termination of this Agreement.
13.2 Set Point Date: For the purpose of this Operating Agreement, it
---------------
is necessary to describe and define the point in time when, due to
depletion, the volume of gas produced or producible from the "B" Contract
acreage is not sufficient to allow the delivery of any volume of natural
gas to CIG in excess of Mesa's takes under the "B" Contract, as amended, if
such lack of deliverability cannot be remedied or overcome by reasonable
and prudent operations.
13.2.1 Subject to the other provisions of this Operating Agreement,
when, during a period of three hundred sixty-five (365) consecutive days
there is not sufficient deliverability from the wells subject to this
Operating Agreement from which CIG is otherwise entitled to take gas to
permit delivery of any volume of natural gas to CIG for CIG's downstream
purchasers, the Set Point Date shall be deemed to have occurred as of the
last day of such 365-day period.
13.2.2 Within sixty (60) days after occurrence of the Set Point Date,
CIG and Mesa agree that all of the functions and responsibilities contained
in paragraphs 5.4, 5.4.1, 5.4.2, 5.5, 5.5.1, 5.5.2, 5.7 and 5.8 shall be
transferred to Mesa. CIG and Mesa further agree to cooperate fully each
with the other party to insure, to the extent reasonably possible, that the
transfer of the enumerated responsibilities shall be accomplished in a
timely and efficient manner. Upon Mesa's assumption of such
responsibilities and the functions associated therewith, Mesa shall perform
all such responsibilities in a reasonable and prudent manner, and shall
further communicate with CIG as to each referenced item in the event
reasonable and relevant information and/or data is required by CIG.
13.2.3 Subsequent to the Set Point Date, CIG shall if appropriate and
feasible in its sole judgment and subject to compliance with any applicable
regulatory approvals or limitations, consider and discuss with Mesa the
transfer to CIG's interest in the leases, wells, wellhead and downhole
equipment.
ARTICLE XIV
Compliance with Laws and Regulations
14.1 General: This Operating Agreement shall be subject to the
--------
conservation laws of the State of Texas, to the valid rules, regulations
and orders of any duly constituted regulatory body of said state, and to
all other applicable Federal, state and local laws, ordinances, rules,
regulations and orders. Attached hereto and made a part hereof is Exhibit
"E" which provides for Equal Employment Opportunity and Certification of
Nonsegregated Facilities.
14.2 Choice of Law: This Operating Agreement and all matters which
--------------
pertain thereto, including, but not limited to, matters of performance,
nonperformance, breach, remedies, procedures, rights, duties and
interpretation or construction, shall be governed and determined by the law
of the State of Texas.
14.3 Regulatory Approval: In the event the terms of this Operating
--------------------
Agreement or the accounting procedure attached as Exhibit "C" are involved
in a proceeding of any kind whatsoever before the Federal Energy Regulatory
Commission, or its successor agency (FERC), CIG shall provide Mesa with
notice and the opportunity to participate in such proceeding. In the event
that the FERC disapproves of this Agreement, or parts hereof, or conditions
its approval on terms which are not acceptable to both Mesa and CIG, unless
otherwise agreed, this Operating Agreement and its exhibits shall terminate
upon issuance of a final, unappealable order.
ARTICLE XV
Engineering Committee
An Engineering Committee shall be established to discuss various
operational matters pertaining to the production, gathering and delivery of
gas produced from wells on the Contract Area. The purpose of this
Committee is to exchange current operating information and future operating
plans with respect to such wells so that the leases, wells and gathering
system may be operated in a manner that maximizes, to the extent possible,
the goals of both parties hereto; provided, however, that the Committee
shall have no authority to authorize operation, maintenance or
construction. Operator and CIG shall each be allowed three representatives
on the Committee and such representatives may be changed from time to time
at the will of the parties. The Committee shall meet at least twice
annually during the first and third quarters of each year. A Chairman
shall be selected for the coming year during the first quarterly meeting.
The chairmanship shall rotate between Operator and CIG each year. More
frequent meetings can be called by the Chairman and information can be
exchanged between the Committee members at will. The existence of the
Committee shall in no way restrict contact between other employees of
Operator and CIG, but is intended to ensure the exchange of information and
plans necessary for efficient management of the remaining gas reserves and
for operation of the wells and gathering system.
ARTICLE XVI
Miscellaneous
16.1 Headings: The headings of the several articles and sections in
---------
this Operating Agreement are inserted for convenience only and shall not
control or affect the meaning or construction of any provision hereof.
16.2 Counterparts: This Operating Agreement may be executed in
-------------
duplicate, and each such copy shall be considered as an original.
16.3 Delegation of Duties by Mesa: Mesa may not delegate its
-----------------------------
duties as Operator hereunder without the prior written consent of CIG,
except in case of merger, consolidation, or assignment to a wholly owned
subsidiary or parent company, and then only upon condition that the
successor operator shall accept and agree to perform the continuing
covenants of this Operating Agreement; provided, however, that Mesa shall
remain responsible for compliance with and performance of the terms of this
Operating Agreement. Any attempted assignment or delegation in violation
of this clause shall be in all respects null and void.
IN WITNESS WHEREOF this Agreement is executed to be effective as of
January 1, 1990.
Attest: MESA OPERATING LIMITED PARTNERSHIP
By: Pickens Operating Co., the
General Partner
By: (s) Richard W. Petrie By: (s) Paul W. Cain
----------------- ---------------------------
Assistant Secretary Paul W. Cain, President and
Chief Operating Officer
Attest: COLORADO INTERSTATE GAS COMPANY
By: (s) Donna M. Foos By: (s) Kenneth M. O'Connell
---------------- --------------------------
Assistant Secretary Kenneth M. O'Connell
Senior Vice President
<PAGE>
EXHIBIT "A"
Attached to and made a part of that certain Operating Agreement by and
between MESA OPERATING LIMITED PARTNERSHIP ("MESA"), as Operator, and
COLORADO INTERSTATE GAS COMPANY ("CIG"), as Nonoperator, and dated January
8, 1988.
<TABLE>
<CAPTION>
NAME OF WELL, COUNTY, LOCATION, AND WORKING INTEREST
WEST PANHANDLE FIELD, TEXAS
CIG Location Location
Meter ------------------------ Working Meter ----------------------- Working
Well Name Number County Sur-Blk-Sec Interest Well Name Number County Sur-Blk-Sec Interest
- --------- ------ ------ ----------- -------- --------- ------- ------- ------------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Allison 1R 02210 Potter WTPalmer 1 1.0 Bivins A-37 10760 Moore ELRR PMc., 15 1.0
Allison A-2 02320 Potter WTPalmer 1 1.0 Bivins A-38 10770 Potter D&P 0-18, 10 1.0
Bivins A-39 10780 Potter G&M M-20, 40 1.0
Baker A-1 03220 Moore D&P 0-18, 39 1.0 Bivins A-40 10790 Potter G&M M-20, 32 1.0
Bivins 2R 09070 Potter D&P 0-18, 21 1.0 Bivins A-41 10800 Potter G&M M-20, 16 1.0
Bivins 4R 09220 Potter G&M M-20, 15 1.0
Bivins 6R 09270 Potter G&M M-20, 40 1.0 Bivins A-42 10810 Potter H&TC 46, 97 1.0
Bivins 7R 09320 Hutchinson G&CNG Y-2, 11 1.0 Bivins A-43 10820 Potter D&P 0-18, 12 1.0
Bivins A-44 10830 Potter G&M M-20, 41 1.0
Bivins 8R 09370 Hutchinson H&TC 46, 88 1.0 Bivins A-46 10840 Potter G&M 5, 11 1.0
Bivins 9R 09420 Moore H&TC 46, 93 0.670619 Bivins A-47 10850 Potter H&TC 46, 101 1.0
Bivins 11R 09520 Potter G&M M-20, 41 1.0
Bivins 12R 09570 Potter G&M M-20, 32 1.0 Bivins A-49 10870 Potter H&TC 46, 105 1.0
Bivins 13R 09620 Potter G&M M-20, 33 1.0 Bivins A-50 10880 Potter D&P 0-18, 28 1.0
Bivins A-51 10890 Potter G&M M-20, 14 0.908250
Bivins 15R 09720 Potter H&TC 46, 108 1.0 Bivins A-52 10900 Moore ELRR PMc, 25 1.0
Bivins 17R 09820 Hutchinson H&TC 46, 90 1.0 Bivins A-53 10910 Potter H&TC 46, 107 0.937500
Bivins 18R 09870 Hutchinson GBCNG Y-2, 13 1.0
Bivins 19R 09920 Moore WTPalmer 4 1.0 Bivins A-54 10920 Moore ELRR PMc, 14 1.0
Bivins 20R 09960 Potter H&TC 46, 97 1.0 Bivins A-55 10930 Moore G&M 2, 75 1.0
Bivins A-56 10940 Hartley CSS 21, 5 1.0
Bivins 23R 09980 Potter D&P 0-18, 12 1.0 Bivins A-57 10950 Potter G&M M-20, 46 1.0
Bivins 24R 09990 Moore ELRR PMc, 25 1.0 Bivins A-58 10960 Hartley G&M 2, 12 1.0
Bivins 25R 10000 Potter DP 0-18, 27 1.0
Bivins 26R 10010 Potter G&M 2, 81 1.0 Bivins A-60 10980 Hartley ELRR 25, 3 1.0
Bivins 28R 10029 Moore ELRR PMc, 33 1.0 Bivins A-61 10990 Hartley ELRR 25, 2 1.0
Bivins A-62 11000 Hartley ELRR 25, 1 1.0
Bivins 29R 10039 Potter G&M 2, 57 1.0 Bivins A-63 11010 Hartley CSS 21, 10 1.0
Bivins 30R 10049 Potter D&P 0-18, 31 1.0 Bivins A-64 11020 Hartley CSS 21, 11 1.0
Bivins 31R 10050 Potter D&P 0-18, 10 1.0
Bivins 32R 10060 Potter D&P 0-18, 11 1.0 Bivins A-65 11030 Hartley G&M 2, 16 1.0
Bivins 33R 10070 Potter D&P 0-18, 2 1.0 Bivins A-66 11040 Moore G&M 2, 72 1.0
Bivins A-67 11050 Moore G&M 2, 74 1.0
Bivins 34R 10080 Potter D&P 0-18, 15 1.0 Bivins A-68 11060 Moore H&TC 44, 99 1.0
Bivins 35R 10090 Potter D&P 0-18, 16 1.0 Bivins A-69 11070 Potter D&P 0-18, 5 1.0
Bivins 37R 101110 Potter D&P 0-18, 26 1.0
Bivins 38R 10120 Potter D&P 0-18, 22 1.0 Bivins A-70 11080 Potter D&P 0-18, 9 1.0
Bivins 39R 10130 Potter D&P 0-18, 14 1.0 Bivins A-71 11090 Hartley CSS 21, 9 1.0
Bivins A-72 11100 Hartley CSS 21, 14 1.0
Bivins 41R 10140 Potter D&P 0-18, 44 1.0 Bivins A-73 11110 Potter ELRR 22, 5 1.0
Bivins 43R 10150 Potter D&P 0-18, 13 1.0 Bivins A-74 11120 Potter G&M 5, 18 1.0
Bivins 44R 10160 Potter D&P 0-18, 28 1.0
Bivins 46R 10170 Potter D&P 0-18, 9 1.0 Bivins A-76 11140 Hartley CSS 21, 13 1.0
Bivins 47R 10180 Moore ELRR PMc, 23 1.0 Bivins A-77 11150 Moore G&M 2, 71 1.0
Bivins A-78 11160 Hartley G&M 2, 20 1.0
Bivins A48R 10300 Potter D&P 0-18, 23 1.0 Bivins A-79 11170 Potter G&M M-20, 5 1.0
Bivins 49R 10310 Potter D&P 0-18, 5 1.0 Bivins A-80 11180 Potter G&M M-20, 6 1.0
Bivins 52R 10320 Potter D&P 0-18, 36 1.0
Bivins 53R 10330 Potter G&M 2, 58 1.0 Bivins A-81 11190 Potter G&M M-20, 13 1.0
Bivins 63R 10340 Potter D&P 0-18, 33 1.0 Bivins A-82 11200 Moore ELRR 1, 1 1.0
Bivins A-83 11210 Potter D&P 0-18, 45 1.0
Bivins 64R 10341 Potter G&M M-20, 31 1.0 Bivins A-84 11220 Potter G&M M-20, 7 1.0
Bivins 72R 10344 Potter G&M 2, 55 1.0 Bivins A-85 11230 Potter G&M M-20, 12 1.0
Bivins 75R 10347 Moore H&TC 46, 95 0.750585
Bivins 76R 10348 Potter H&TC 46, 101 1.0 Bivins A-86 11240 Potter G&M M-20, 18 1.0
Bivins A-87 11250 Potter G&M M-20, 19 1.0
Bivins 77R 10349 Potter H&TC 46, 103 1.0 Bivins A-88 11260 Potter D&P 0-18, 21 1.0
Bivins 80R 10352 Potter D&P 0-18, 34 1.0 Bivins A-89 11270 Potter G&M 2, 21 1.0
Bivins 82R 10354 Potter D&P 0-18, 7 1.0 Bivins A-90 11280 Hartley CSS 21, 21 1.0
Bivins 85R 10356 Moore H&TC 47, 54 1.0
Bivins 86R 10357 Potter ELRR B-11, 29 1.0 Bivins A-91 11290 Potter G&M 2, 58 1.0
Bivins A-92 11300 Potter ELRR B-11, 34 1.0
Bivins A2R 10470 Potter D&P 0-18, 13 1.0 Bivins A-95 11320 Potter D&P 0-18, 37 1.0
Bivins A-3 10480 Potter G&M M-20, 30 1.0 Bivins A-96 11330 Potter D&P 0-18, 16 1.0
Bivins A-5 10500 Potter D&P 0-18, 25 1.0 Bivins A-97 11340 Hartley G&M 2, 19 1.0
Bivins A-7 10520 Hartley ELRR 25, 7 1.0
Bivins A-8 10530 Hartley ELRR 25, 4 1.0 Bivins A-98 11350 Potter G&M 2, 59 1.0
Bivins A-99 11360 Potter D&P 0-18, 44 1.0
Bivins A-9 10540 Hartley CSS 21, 6 1.0 Bivins A-100 11370 Potter D&P 0-18, 36 1.0
Bivins A-13 10560 Potter D&P 0-18, 7 1.0 Bivins A-101 11380 Potter D&P 0-18, 34 1.0
Bivins A-16 10590 Potter G&M M-20, 33 1.0 Bivins A-102 11390 Potter D&P 0-18, 31 1.0
Bivins A-18 10610 Potter G&M M-20, 17 1.0
Bivins A-19 10620 Potter G&M M-20, 29 1.0 Bivins A-103 11400 Potter G&M 2, 81 1.0
Bivins A-104 11410 Potter G&M 2, 57 1.0
Bivins A-20 10630 Potter G&M M-20, 35 1.0 Bivins A-105 11420 Potter D&P 0-18, 38 1.0
Bivins A-21 10640 Moore ELRR PMc, 33 1.0 Bivins A-106 11430 Potter ELRR B-11, 30 1.0
Bivins A-23 10660 Potter ELRR 22, 8 1.0 Bivins A-108 11440 Potter D&P 0-18, 17 1.0
Bivins A-24 10670 Moore ELRR PMc, 23 1.0
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT "A"
(Continued)
NAME OF WELL, COUNTY, LOCATION, AND WORKING INTEREST
WEST PANHANDLE FIELD, TEXAS
CIG Location Location
Meter ------------------------ Working Meter ----------------------- Working
Well Name Number County Sur-Blk-Sec Interest Well Name Number County Sur-Blk-Sec Interest
- --------- ------ ------ ----------- -------- --------- ------- ------- ------------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Bivins A-25 10680 Potter D&P 0-18, 2 1.0 Bivins A-109 11450 Potter G&M 2, 70 1.0
Bivins A-110 11460 Potter D&P 0-18, 8 1.0
Bivins A-29 10690 Moore H&TC 47, 55 1.0 Bivins A-111 11470 Oldham G&M 2, 22 1.0
Bivins A-33 10720 Potter D&P 0-18, 35 1.0 Bivins A-112 11480 Potter ELRR 22, 6 1.0
Bivins A-34 10730 Hartley ELRR 25, 5 1.0 Bivins A-113 11490 Potter ELRR 22, 7 1.0
Bivins A-35 10740 Potter D&P 0-18, 40 1.0
Bivins A-36 10750 Potter D&P 0-18, 43 1.0
Bivins A-114 11500 Potter ELRR 22, 3 1.0 Bost 3R 14440 Hutchinson TTRR Y-2, 9 1.0
Bivins A-115 11510 Potter AB&M 22, 10 1.0 Bost A-2 15075 Hutchinson TTRR Y-2, 6 1.0
Bivins A-116 11520 Potter AB&M 22, 9 1.0 Bost B-1 15160 Hutchinson TTRR Y-2, 9 1.0
Bivins A-117 11530 Potter BS&F 22, 11 1.0 Bost C-3 15340 Hutchinson TTRR Y-2, 10 1.0
Bivins A-118 11540 Potter BS&F 22, 12 1.0 Bost C-4 15350 Carson TTRR Y-2, 10 1.0
Bivins A-119 11550 Potter G&M M-20, 20 1.0 Bost D-2 15440 Hutchinson BS&F 1 1.0
Bivins A-120 11560 Potter G&M M-20, 11 1.0 Bradley A-1 20120 Potter ELRR B-11, 8 1.0
Bivins A-122 11570 Potter ELRR 22, 2 1.0
Bivins A-124 11580 Potter G&M 5, 23 1.0 Cooper A-1 27040 Moore ELRR PMc, 16 1.0
Bivins A-125 11590 Hartley CSS 21, 20 1.0 Coughlin 1R 27300 Potter D&P 0-18, 77 1.0
Coughlin 2R 27310 Potter D&P 0-18, 1 1.0
Bivins A-128 11600 Potter D&P 0-18, 6 1.0 Coughlin A-1 27340 Potter D&P 0-18, 1 1.0
Bivins A-129 11610 Potter D&P 0-18, 32 1.0 Coughlin A-2 27390 Potter D&P 0-18, 77 1.0
Bivins A-130 11620 Potter D&P 0-18, 33 1.0
Bivins A-131 11630 Hartley CSS 21, 8 1.0 Crawford 1R 27640 Moore ELRR PMc, 24 1.0
Bivins A-132 11640 Potter G&M M-20, 36 1.0 Crawford 2R 27650 Potter ELRR PMc, 34 1.0
Crawford 3R 27660 Potter D&P 0-18, 68 1.0
Bivins A-133 11650 Potter G&M M-20, 4 1.0 Crawford 4R 27670 Potter D&P 0-18, 78 1.0
Bivins A-134 11660 Potter G&M M-20, 3 1.0 Crawford 5R 27680 Potter D&P 0-18, 4 1.0
Bivins A-135 11670 Potter H&TC 46, 108 1.0
Bivins A-136 11680 Potter G&M 5, 20-1/2 0.781250 Crawford 6R 27690 Potter D&P 0-18, 80 1.0
Bivins A-137 11690 Moore G&M 3, 48 1.0 Crawford 7R 27700 Moore ELRR PMc, 26 1.0
Crawford A-2 27890 Moore ELRR PMc, 34 1.0
Bivins A-139 11710 Potter D&P 0-18, 14 1.0 Crawford A-3 27891 Moore ELRR PMc, 26 1.0
Bivins A-143 11720 Potter G&M 2, 55 1.0 Crawford B-1 27940 Potter D&P 0-18, 78 1.0
Bivins A-144 11730 Hartley G&M 2, 14 1.0
Bivins A-145 11740 Hartley CSS 21, 2 1.0 Crawford B-2 28090 Potter D&P 0-18, 80 1.0
Bivins A-146 11750 Hartley CSS 21, 16 1.0 Crawford C-2 28190 Moore ELRR PMc, 32 1.0
Crawford C-3 28195 Moore ELRR PMc, 24 1.0
Bivins A-148 11770 Hartley CSS 21, 7 1.0 Crawford D-2 28290 Potter D&P 0-18, 4 1.0
Bivins A-149 11780 Potter D&P 0-18, 20 1.0 Crawford D-3 28340 Moore ELRR PMc, 32 1.0
Bivins A-150R 11790 Potter D&P 0-18, 18 1.0
Bivins A-151 11800 Potter D&P 0-18, 11 1.0 Crawford D-4 28341 Potter D&P 0-18, 68 1.0
Bivins A-152 11810 Moore D&P 0-18, 41 1.0
Dunaway 1R 30900 Hutchinson TTRR Y-2, 5 1.0
Bivins A-153 11820 Potter ELRR B-11, 33 1.0 Dunaway A-3 31000 Hutchinson TTRR Y-2, 5 1.0
Bivins A-154 11830 Moore D&P 0-18, 46 1.0 Dunaway A-4 31055 Hutchinson TTRR Y-2, 5 1.0
Bivins A-155 11840 Potter D&P 0-18, 19 1.0 Dunaway A3R 31050 Hutchinson TTRR Y-2, 5 1.0
Bivins A-157 11860 Potter G&M M-20, 31 1.0 Dunaway B-1 31100 Hutchinson TTRR Y-2, 5 1.0
Bivins A-158 11870 Potter WTPalmer 5 1.0
Fee 2R 33830 Moore G&M 3, 51 1.0
Bivins A-159 11880 Potter D&P 0-18, 13 1.0 Fee 3R 33840 Moore H&TC 47, 53 1.0
Bivins A-160 11890 Hutchinson H&TC 46, 90 1.0 Fee A-1 33870 Moore G&M 3, 76 1.0
Bivins A-160R 11900 Hutchinson H&TC 46, 90 1.0 Fee A-2 33920 Moore H&TC 47, 53 1.0
Bivins A-161 11910 Hutchinson GBCNG Y-2, 13 1.0 Fee A-3 33970 Moore G&M 3, 50 1.0
Bivins A-162 11920 Potter D&P 0-18, 24 1.0
Fee A-4 34020 Moore G&M 3, 51 1.0
Bivins A-163 11930 Potter H&TC 46, 103 1.0 Fee A-5 34070 Moore D&P B-12, 10 1.0
Bivins A-164 11940 Hutchinson H&TC 46, 88 1.0 Fee A-6 34120 Moore G&M 3, 79 1.0
Bivins A-165 11950 Potter H&TC 46, 99 1.0
Bivins A-166 11960 Potter H&TC 46, 106 0.910156 Gage 1R 37100 Potter ELRR B-11, 7 1.0
Bivins A-167 11970 Potter G&M M-20, 15 1.0
Johnson 1R 50160 Hutchinson TTRR Y-2, 3 1.0
Bivins A-168 12100 Moore WTPalmer 4 1.0 Johnson 2R 50170 Hutchinson TTRR Y-2, 3 1.0
Bivins A-169R 12110 Potter D&P 0-18, 23 1.0 Johnson A-2 50410 Hutchinson TTRR Y-2, 3 1.0
Bivins A-170 12120 Potter D&P 0-18, 22 1.0 Johnson A-3 50420 Hutchinson TTRR Y-2, 4 1.0
Bivins A-171 12130 Potter D&P 0-18, 23 1.0
Bivins A-172 12140 Moore WRBouldin N-1, 1.0 Killgore 1-R 52830 Moore ELRR PMc, 18 1.0
Killgore 3-R 52832 Moore ELRR PMc, 21 1.0
Bivins A-173 12150 Moore G&M 2, 73 1.0 Killgore A-2 52920 Moore ELRR PMc, 20 1.0
Bivins A-174 12160 Hartley ELRR 25, 6 1.0 Killgore A-5 53070 Moore H&TC 44, 12 1.0
Bivins A-175 12161 Hartley ELRR 25, 8 1.0 Killgore A-6 53120 Moore H&TC 44, 13 1.0
Bivins A-176 12162 Potter ELRR 22, 4 1.0
Bivins A-177 11979 Hartley G&M 2, 18 1.0 Killgore A-7 53170 Moore G&M 2, 77 1.0
Killgore A-10 53270 Moore H&TC 44, 11 1.0
Bivins A-178 12164 Moore G&M 2, 76 1.0 Killgore A-11 53320 Moore ELRR PMc, 17 1.0
Bivins A-179 12165 Potter D&P 0-18, 15 1.0 Killgore A-12 53370 Moore ELRR PMc, 19 1.0
Bivins A-180 12166 Hartley G&M 2, 13 1.0 Killgore A-13 53420 Moore ELRR PMc, 11 1.0
Bivins A-182 11973 Hartley CSS 21, 15 1.0
Bivins A-183 11974 Potter D&P 0-18, 26 1.0 Killgore A-13 53320 Moore ELRR PMc, 13 1.0
Killgore A-16 53570 Moore H&TC 44, 31 1.0
Bivins B-1 11980 Hutchinson B&B Y-2, 11 1.0 Killgore A-17 53580 Moore ELRR PMc, 21 1.0
Bivins B-3 11990 Carson GBCNG Y-2, 15 1.0 Killgore A-18 53581 Moore ELRR PMc, 18 1.0
Bivins B-6 12000 Hutchinson H&TC 46, 90 1.0 Killgore A-19 53582 Moore ELRR PMc, 12 1.0
Bivins E-1 12010 Potter D&P 0-18, 27 1.0
Bivins G-1 12020 Moore H&TC 46, 93 0.670619 Killgore A-20 53583 Moore ELRR PMc, 7 1.0
Killgore A-21 53584 Moore ELRR Pmc, 6 1.0
Bivins H-1 12030 Moore H&TC 46, 95 0.750585 Killgore B-1 53620 Moore ELRR Pmc, 22 1.0
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT "A"
(Continued)
NAME OF WELL, COUNTY, LOCATION, AND WORKING INTEREST
WEST PANHANDLE FIELD, TEXAS
CIG Location Location
Meter ------------------------ Working Meter ----------------------- Working
Well Name Number County Sur-Blk-Sec Interest Well Name Number County Sur-Blk-Sec Interest
- --------- ------ ------ ----------- -------- --------- ------- ------- ------------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Bivins J-1 12050 Moore H&TC 47, 54 1.0
Bivins 81R 12890 Potter D&P 0-18, 8 1.0 Lubberstedt 1R 57430 Moore ELRR PMc, 27 1.0
Bost 1R 13900 Hutchinson TTRR Y-2, 10 1.0 Lubberstedt A2 57441 Moore ELRR PMc, 27 1.0
Bost 2R 14170 Hutchinson TTRR Y-2, 6 1.0
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT "A"
(Continued)
NAME OF WELL, COUNTY, LOCATION, AND WORKING INTEREST
WEST PANHANDLE FIELD, TEXAS
CIG Location Location
Meter ------------------------ Working Meter ----------------------- Working
Well Name Number County Sur-Blk-Sec Interest Well Name Number County Sur-Blk-Sec Interest
- --------- ------ ------ ----------- -------- --------- ------- ------- ------------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Masterson 1R 58710 Moore D&P 0-18, 76 1.0 Masterson 85R 59573 Potter H&TC 47, 64 1.0
Masterson 2R 58760 Moore D&P 0-18, 85 1.0 Masterson 86R 59574 Potter ELRR B-10, 34 1.0
Masterson 3R 58810 Moore D&P 0-18, 86 1.0 Masterson 91R 59579 Potter D&P 0-18, 72 1.0
Masterson 5R 58860 Potter H&TC 47, 65 1.0 Masterson 92R 59580 Potter ELRR B-11, 5 1.0
Masterson 6R 58910 Moore G&M 3, 40 1.0 Masterson 93R 59581 Potter ELRR B-11, 9 1.0
Masterson 7R 58960 Potter D&P 0-18, 65 1.0 Masterson 95R 59583 Potter G&M 3, 30 1.0
Masterson 9R 59020 Potter D&P 0-18, 64 1.0 Masterson 97R 59585 Potter H&TC 47, 60 1.0
Masterson 10R 59030 Potter D&P 0-18, 104 1.0 Masterson 99R 59587 Moore G&M 3, 36 1.0
Masterson 11R 59040 Potter D&P 0-18, 67 1.0 Masterson 100R 59588 Moore ELRR B-10, 30 1.0
Masterson 12R 59050 Potter ELRR B-10, 35 1.0 Masterson 101R 59589 Moore G&M 3, 37 1.0
Masterson 13R 59070 Potter D&P 0-18, 63 1.0 Masterson 102R 59590 Moore ELRR B-10, 13 1.0
Masterson 15R 59090 Potter D&P 0-18, 103 1.0 Masterson 103R 59591 Moore ELRR 8-10, 29 1.0
Masterson 16R 59100 Potter G&M 3, 24 1.0 Masterson 104R 59592 Potter H&TC 47, 58 1.0
Masterson 19R 59130 Potter G&M 3, 33 1.0 Masterson 105R 59593 Potter H&TC 47, 61 1.0
Masterson 20R 59140 Potter D&P 0-18, 110 1.0 Masterson 106R 59594 Potter G&M 3, 81 1.0
Masterson 21R 59150 Potter D&P 0-18, 107 1.0 Masterson 107R 59595 Potter ELRR B-11, 14 1.0
Masterson 22R 59160 Potter G&M 3, 10 1.0 Masterson A-1 59660 Moore G&M 3, 46 1.0
Masterson 23R 59170 Potter D&P 0-18, 71 1.0 Masterson A-2 59670 Moore G&M 3, 49 1.0
Masterson 24R 59180 Potter D&P 0-18, 69 1.0 Masterson A-3 59680 Moore G&M 3, 45 1.0
Masterson 25R 59190 Potter D&P 0-18, 106 1.0 Masterson A-4 59690 Moore ELRR B-10, 33 1.0
Masterson 27R 59200 Potter G&M 3, 27 1.0 Masterson A-5 59700 Moore D&P 0-18, 76 1.0
Masterson 28R 59210 Potter D&P 0-18, 3 1.0 Masterson A-6 59710 Moore D&P 0-18, 73 1.0
Masterson 29R 59220 Potter G&M 3, 22 1.0 Masterson A-7 59720 Moore D&P B-12, 11 1.0
Masterson 30R 59230 Potter D&P 0-18, 92 1.0 Masterson A-9 59730 Potter ELRR B-10, 36 1.0
Masterson 31R 59240 Moore D&P 0-18, 84 1.0 Masterson A-10 59740 Moore D&P B-12, 13 1.0
Masterson 32R 59250 Potter D&P 0-18, 74 1.0 Masterson A-11 59750 Moore D&P B-12, 12 1.0
Masterson 33R 59260 Potter D&P 0-18, 72 1.0 Masterson A-12 59760 Moore ELRR B-10, 27 1.0
Masterson 34R 59270 Potter D&P 0-18, 94 1.0 Masterson A-13 59770 Potter D&P 0-18, 74 1.0
Masterson 35R 59280 Potter D&P 0-18, 101 1.0 Masterson A-14 59780 Moore D&P 0-18, 60 1.0
Masterson 36R 59290 Potter ELRR B-11, 10 1.0 Masterson A-15 59790 Moore D&P 0-18, 62 1.0
Masterson 37R 59300 Potter ELRR B-11, 1 1.0 Masterson A-16 59800 Moore G&M 3, 41 1.0
Masterson 38R 59310 Potter D&P 0-18, 100 1.0 Masterson A-17 59810 Moore R B Newcombe 1 1.0
Masterson 39R 59320 Potter D&P 0-18, 90 1.0 Masterson A-18 59820 Moore G&M 3, 40 1.0
Masterson 40R 59330 Moore G&M 3, 39 1.0 Masterson A-19 59830 Potter D&P 0-18, 3 1.0
Masterson 41R 59340 Potter D&P 0-18, 79 1.0 Masterson A-20 59840 Moore ELRR B-10, 32 1.0
Masterson 42R 59350 Potter D&P 0-18, 70 1.0 Masterson A-21 59850 Moore ELRR B-10, 17 1.0
Masterson 43R 59360 Potter G&M 3, 20 1.0 Masterson A-22 59860 Moore D&P 0-18, 83 1.0
Masterson 44R 59370 Potter H&TC 47, 65 1.0 Masterson A-23 59870 Potter G&M 2, 84 1.0
Masterson 46R 59390 Potter D&P 0-18, 96 1.0 Masterson A-25 59880 Potter ELRR B-11, 12 1.0
Masterson 47R 59400 Potter D&P 0-18, 89 1.0 Masterson A-26 59890 Potter G&M 2, 83 1.0
Masterson 48R 59410 Potter G&M 3, 33 1.0 Masterson A-29 59920 Potter G&M 3, 13 1.0
Masterson 49R 59420 Potter G&M 3, 36 1.0 Masterson A-31 59930 Moore D&P 0-18, 61 1.0
Masterson 50R 59430 Moore D&P 0-18, 87 1.0 Masterson A-32 59940 Moore G&M 3, 48 1.0
Masterson 51R 59440 Moore G&M 3, 40 1.0 Masterson A-37 59941 Potter D&P 0-18, 94 1.0
Masterson 53R 59460 Potter D&P 0-18, 91 1.0 Masterson A-40 59944 Potter G&M 3, 9 1.0
Masterson 54R 59470 Moore G&M 3, 39 1.0 Masterson B-1 59950 Moore G&M 3, 43 1.0
Masterson 55R 59480 Potter ELRR B-11, 4 1.0 Masterson B-3 59970 Potter G&M 3, 42 1.0
Masterson 56R 59490 Potter G&M 3, 32 1.0 Masterson B-6 59980 Potter G&M 3, 19 1.0
Masterson 57R 59500 Potter D&P 0-18, 109 1.0 Masterson B-8 59990 Potter D&P 0-18, 89 1.0
Masterson 58R 59510 Potter G&M 3, 28 1.0 Masterson B-11 60010 Potter H&TC 47, 56 1.0
Masterson 60R 59530 Potter G&M 3, 21 1.0 Masterson B-13 60020 Potter H&TC 47, 58 1.0
Masterson 62R 59550 Potter H&TC 47, 68 1.0 Masterson B-14 60030 Potter H&TC 47, 59 1.0
Masterson 63R 59551 Potter D&P 0-18, 81 1.0 Masterson B-15 60040 Moore ELRR B-10, 19 1.0
Masterson 68R 59556 Potter G&M 3, 29 1.0 Masterson B-16 60050 Potter D&P 0-18, 71 1.0
Masterson 69R 59557 Potter D&P 0-18, 98 1.0 Masterson B-17 60060 Potter D&P 0-18, 72 1.0
Masterson 70R 59558 Potter D&P 0-18, 97 1.0 Masterson B-18 60070 Moore G&M 3, 37 1.0
Masterson 71R 59559 Moore G&M 3, 85 1.0 Masterson B-19 60080 Potter G&M 3, 35 1.0
Masterson 72R 59560 Potter D&P 0-18, 83 1.0 Masterson B-20 60090 Potter G&M 3, 33 1.0
Masterson 73R 59561 Potter G&M 3, 14 1.0 Masterson B-21 60100 Potter D&P 0-18, 63 1.0
Masterson 74R 59562 Potter G&M 3, 15 1.0 Masterson B-22 60110 Potter D&P 0-18, 64 1.0
Masterson 75R 59563 Potter G&M 3, 15 1.0 Masterson B-23 60120 Potter H&TC 47, 61 1.0
Masterson 76R 59564 Potter D&P 0-18, 99 1.0 Masterson B-24 60130 Potter G&M 3, 30 1.0
Masterson 77R 59565 Potter D&P 0-18, 88 1.0 Masterson B-25 60140 Potter H&TC 47, 60 1.0
Masterson 78R 59566 Potter G&M 3, 83 1.0 Masterson B-26 60150 Potter H&TC 47, 63 1.0
Masterson 79R 59567 Potter G&M 3, 31 1.0 Masterson B-27 60160 Potter G&M 3, 27 1.0
Masterson 80R 59568 Potter G&M 3, 84 1.0 Masterson B-29 60180 Potter G&M 3, 28 1.0
Masterson 81R 59569 Potter G&M 3, 35 1.0 Masterson B-30 60190 Moore D&P 0-18, 87 1.0
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT "A"
(Continued)
NAME OF WELL, COUNTY, LOCATION, AND WORKING INTEREST
WEST PANHANDLE FIELD, TEXAS
CIG Location Location
Meter ------------------------ Working Meter ----------------------- Working
Well Name Number County Sur-Blk-Sec Interest Well Name Number County Sur-Blk-Sec Interest
- --------- ------ ------ ----------- -------- --------- ------- ------- ------------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Masterson 82R 59570 Potter G&M 2, 84 1.0 Masterson B-31 60200 Potter H&TC 47, 65 1.0
Masterson 83R 59571 Potter G&M 3, 19 1.0 Masterson B-32 60210 Potter H&TC 47, 64 1.0
Masterson 84R 59572 Potter G&M 3, 17 1.0 Masterson B-33 60220 Potter G&M 3, 18 1.0
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT "A"
(Continued)
NAME OF WELL, COUNTY, LOCATION, AND WORKING INTEREST
WEST PANHANDLE FIELD, TEXAS
CIG Location Location
Meter ------------------------ Working Meter ----------------------- Working
Well Name Number County Sur-Blk-Sec Interest Well Name Number County Sur-Blk-Sec Interest
- --------- ------ ------ ----------- -------- --------- ------- ------- ------------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Masterson B34R 60235 Potter G&M 3, 15 1.0 Masterson G-4 60870 Potter D&P 0-18, 79 1.0
Masterson B-37 60240 Potter H&TC 47, 66 1.0 Masterson G-5 60880 Moore D&P 0-18, 86 1.0
Masterson B-39 60260 Potter D&P 0-18, 107 1.0 Masterson J-1 60900 Moore D&P 0-18, 59 1.0
Masterson B-40 60270 Potter D&P 0-18, 90 1.0 Masterson J-3 60920 Potter ELRR B-11, 10 1.0
Masterson B-42 60290 Potter G&M 3, 32 1.0 Masterson J-4 60930 Potter ELRR B-11, 9 1.0
Masterson B-43 60300 Potter ELRR B-10, 35 1.0 Masterson J-5 60940 Potter G&M 3, 11 1.0
Masterson B-44 60310 Potter G&M 3, 81 1.0 Masterson J-6 60950 Potter G&M 2, 80 1.0
Masterson B-45 60320 Potter D&P 0-18, 91 1.0 Masterson J-7 60960 Potter G&M 3, 9 1.0
Masterson B-46 60330 Potter D&P 0-18, 88 1.0 Masterson J-10 60963 Potter D&P 0-18, 69 1.0
Masterson B-47 60340 Potter D&P 0-18, 92 1.0 Masterson M-2 60980 Moore ELRR 8-10, 13 1.0
Masterson B-48 60350 Potter G&M 3, 34 1.0 Masterson M-3 60990 Moore G&M 3, 39 1.0
Masterson B-49 60360 Potter G&M 3, 83 1.0 Masterson M-4 61000 Moore G&M 3, 38 1.0
Masterson B-50 60370 Potter D&P 0-18, 109 1.0 Masterson M-5 61010 Moore ELRR B-10, 14 1.0
Masterson B-51 60380 Potter G&M 3, 25 1.0 Masterson N-1 61020 Potter G&M 3, 17 1.0
Masterson B-52 60390 Potter G&M 3, 24 1.0 Masterson A35R 61202 Potter H&TC 47, 77 1.0
Masterson B-53 60400 Potter D&P 0-18, 98 1.0 Masterson 791R 61208 Potter H&TC 47, 79 1.0
Masterson B-54 60410 Potter G&M 3, 23 1.0 McBride 1R 62810 Potter H&TC 46, 98 1.0
Masterson B55R 60420 Potter G&M 3, 26 1.0 McBride A-2 62880 Potter H&TC 46, 98 1.0
Masterson B-57 60430 Potter H&TC 47, 68 1.0
Masterson B58R 60445 Potter H&TC 47, 67 1.0 Poling 1R 77060 Carson TTRR Y-2, 12 1.0
Poling A-2 77120 Carson TTRR Y-2, 12 1.0
Masterson B-59 60450 Potter G&M 3, 16 1.0
Masterson B-60 60460 Potter D&P 0-18, 106 1.0 Read 3R 78955 Moore ELRR B-10, 18 1.0
Masterson B-61 60470 Potter D&P 0-18, 70 1.0 Read A-2 78670 Moore G&M 3, 47 1.0
Masterson B-62 60480 Potter G&M 3, 31 1.0 Read A-3 78710 Moore D&P B-12, 15 1.0
Masterson B-63 60490 Potter D&P 0-18, 110 1.0 Read A-4 78750 Moore ELRR B-10, 18 1.0
Masterson B64R 60500 Potter D&P 0-18, 95 1.0
Masterson B-65 60510 Potter D&P 0-18, 99 1.0 Read A-6 78830 Moore ELRR B-10, 20 1.0
Masterson B-66 60520 Potter D&P 0-18, 104 1.0 Read A-7 78870 Moore Ozier M-3, 1 1.0
Masterson B-67 60530 Potter D&P 0-18, 100 1.0 Read A-8 78880 Moore D&P B-12, 14 1.0
Masterson B-68 60540 Potter D&P 0-18, 101 1.0 Read B-1 78910 Moore ELRR B-10, 16 1.0
Masterson B-69 60550 Potter G&M 3, 21 1.0 Sanford A-1 81510 Carson AB&M 3, 11 1.0
Masterson B-70 60560 Potter ELRR B-11, 4 1.0 Sanford A-3 81570 Carson AB&M 3, 9 0.875000
Masterson B-72 60580 Potter ELRR B-11, 5 1.0 Sanford A-4 81630 Carson AB&M 3, 10 1.0
Masterson B-73 60590 Potter ELRR B-10, 38 1.0 Sanford A-5 81690 Carson AB&M 3, 8 1.0
Masterson B-74 60600 Potter D&P 0-18, 97 1.0 Sanford A-6 81570 Carson AB&M 3, 16 1.0
Masterson B75R 60610 Potter D&P 0-18, 93 1.0 Sanford A-7 81810 Carson AB&M 3, 4 1.0
Masterson B76R 60620 Potter D&P 0-18, 66 1.0 Seay A-2 84100 Moore G&M 2, 85 1.0
Masterson B-77 60630 Potter D&P 0-18, 103 1.0 Sneed 1R 86550 Moore M.Johnson,Tr.7 1.0
Masterson B78R 60640 Potter D&P 0-18, 105 1.0 Sneed 2R 86610 Moore ELRR B-10, 5 1.0
Masterson B-79 60650 Potter G&M 3, 22 1.0 Sneed 3R 86620 Moore H. Hall 1.0
Masterson B-80 60660 Potter H&TC 47, 62 1.0 Sneed 4R 86630 Moore T&NO 6-T, 51 1.0
Masterson B-81 60670 Potter D&P 0-18, 95 1.0 Sneed 8R 86631 Moore ELRR B-10, 11 1.0
Masterson B-82 60680 Potter D&P 0-18, 66 1.0 Sneed 9R 86632 Moore ELRR B-10, 10 1.0
Masterson B-83 60690 Potter D&P 0-18, 93 1.0 Sneed 11R 86634 Moore T&NO 6-T, 56 1.0
Masterson B-84 60700 Potter D&P 0-18, 105 1.0 Sneed A-2 86730 Moore T&NO 6-T, 54 1.0
Masterson B85R 60710 Potter D&P 0-18, 108 1.0 Sneed A-3 86790 Moore T&NO 6-T, 53 1.0
Masterson B-86 60720 Potter G&M 3, 82 1.0 Sneed A-4 86850 Moore T&NO 6-T, 52 1.0
Masterson B86R 60730 Potter G&M 3, 82 1.0 Sneed A-5 86910 Moore ELRR B-10, 3 1.0
Masterson B87R 60740 Potter G&M 3, 16 1.0 Sneed A-6 86970 Moore ELRR B-10, 7 1.0
Masterson B-88 60750 Potter ELRR B-11, 1 1.0 Sneed A-7 87030 Moore H. Hall 1.0
Masterson B-89 60760 Potter D&P 0-18, 85 1.0 Sneed A-8 87090 Moore H. Hall 1.0
Masterson B-90 60770 Potter G&M 3, 10 1.0 Sneed A-9 87150 Moore ELRR B-10, 8 1.0
Masterson B-91 60780 Potter D&P 0-18, 108 1.0 Sneed A-10 87160 Moore T&NO 6-T, 51 1.0
Masterson B92R 60800 Potter G&M 3, 26 1.0 Sneed B-1 87212 Moore T&NO 6-T, 58 1.0
Masterson B-93 60790 Potter H&TC 47, 58 1.0 Sneed B-2 87270 Moore T&NO 6-T, 57 1.0
Masterson B-94 61030 Potter D&P 0-18, 67 1.0 Sneed B-3 87330 Moore ELRR B-10, 11 1.0
Masterson B-95 61040 Potter G&M 3, 20 1.0 Sneed B-4 87390 Moore T&NO 6-T, 56 1.0
Masterson B-96 61050 Potter D&P 0-18, 96 1.0 Sneed C-1 87450 Moore T&NO 6-T, 46 1.0
Masterson B-98 61052 Potter G&M 3, 15 1.0 Sneed D-7 87510 Moore T&NO 6-T, 47 1.0
Masterson B-99 61053 Potter H&TC 47, 67 1.0 Sneed E-1 87570 Moore M.Johnson,Tr.7 1.0
Masterson B100R 60808 Potter H&TC 47, 65 1.0 State
Masterson B-101 60809 Potter H&TC 47, 70 1.0 Riverbed 1 90330 Potter Canadian River 8 1.0
Masterson B-102 60811 Potter G&M 3, 29 1.0
Masterson B-104 60814 Potter G&M 3, 34 1.0 Thompson 1R 92510 Moore ELRR 26, 26 1.0
Masterson B-105 60815 Moore G&M 3, 44 1.0 Thompson 2R 92520 Moore ELRR 26, 25 1.0
Thompson 5R 92550 Moore ELRR 26, 24 1.0
Masterson C-1 60810 Potter D&P 0-18, 65 1.0 Thompson 8R 92558 Moore ELRR 26, 26 1.0
Masterson C-3 60820 Potter D&P 0-18, 102 1.0 Thompson A-1 92570 Moore ELRR 26, 24 1.0
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT "A"
(Continued)
NAME OF WELL, COUNTY, LOCATION, AND WORKING INTEREST
WEST PANHANDLE FIELD, TEXAS
CIG Location Location
Meter ------------------------ Working Meter ----------------------- Working
Well Name Number County Sur-Blk-Sec Interest Well Name Number County Sur-Blk-Sec Interest
- --------- ------ ------ ----------- -------- --------- ------- ------- ------------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Masterson D4R 60830 Potter D&P 0-18, 108 1.0
Masterson F-1 60840 Potter G&M 3, 14 1.0 Thompson A-2 92600 Moore H&TC 44, 19 1.0
Masterson G-3 60860 Moore D&P 0-18, 84 1.0 Thompson A-3 92630 Moore H&TC 44, 21 1.0
Thompson A-4 92660 Moore ELRR 26, 25 1.0
Thompson A-5 92690 Moore ELRR 26, 23 1.0
Thompson A-6 92720 Moore ELRR 26, 26 1.0
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT "A"
(Continued)
NAME OF WELL, COUNTY, LOCATION, AND WORKING INTEREST
WEST PANHANDLE FIELD, TEXAS
CIG Location Location
Meter ------------------------ Working Meter ----------------------- Working
Well Name Number County Sur-Blk-Sec Interest Well Name Number County Sur-Blk-Sec Interest
- --------- ------ ------ ----------- -------- --------- ------- ------- ------------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Thompson B-2 92750 Moore H&TC 44, 17 1.0
Thompson B-3 92780 Moore D&P 0-18, 75 1.0
Thompson B-4 92810 Moore H&TC 44, 58 1.0
Thompson B-5 92840 Moore H&TC 44, 26 1.0
Thompson B-6 92870 Moore ELRR 26, 19 1.0
Thompson B-7 92900 Moore D&P 0-18, 57 1.0
Thompson B-8 92930 Moore ELRR 26, 17 1.0
Thompson B-9 92960 Moore D&P 0-18, 58 1.0
Thompson B-11 92990 Moore ELRR B-10, 1 1.0
Thompson B-12 93020 Moore ELRR 26, 22 1.0
Thompson B-13 93050 Moore J.T. Sneed, Z 1.0
Thompson B-14 93080 Moore G&M 3, 73 1.0
Thompson C-1 93110 Moore ELRR B-10, 2 1.0
Warrick 1R 95610 Potter GBCNG Y-2, 16 1.0
Warrick 2R 95660 Moore H&TC 46, 92 1.0
Warrick 3R 95710 Potter H&TC 46, 96 1.0
Warrick 4R 95760 Moore H&TC 46, 94 1.0
Warrick A-2 95860 Moore H&TC 46, 92 1.0
Warrick A-3 95910 Moore H&TC 46, 96 1.0
Warrick A-5 96010 Moore H&TC 46, 94 1.0
Warrick A-6 96020 Potter GBCNG Y-2, 16 1.0
Warrick A-7 96040 Carson B&B Y-2, 12 1.0
</TABLE>
<PAGE>
<PAGE>
EXHIBIT "B"
Attached to and made a part of that certain Operating Agreement by and
between MESA OPERATING LIMITED PARTNERSHIP ("MESA"), as Opeator, and
COLORADO INTERSTATE GAS COMPANY ("CIG"), as Nonoperator, and dated January
8, 1988.
LIST OF OPERATING AGREEMENT WITH
WORKING INTEREST PARTNERS
GROSS
LOCATION WORKING
SUR-BLK-SEC INTEREST
WELL WORKING INTEREST PARTNER COUNTY PERCENT
- ----------- ------------------------------------- ----------- --------
Bivins A-51 Jewell E. Park, Independent Executrix
of the Estate of David Ayers Park, Jr. G&M-M20-14 2.3437
Virginia Sherrill Potter 7.0313
Bivins A-53 Jewell E. Park, Independent Executrix
of the Estate of David Ayers Park, Jr. H&TC-46-107 1.5625
Virginia Sherrill Potter 4.6875
Bivins A-136 Jewell E. Park, Independent Executrix
of the Estate of David Ayers Park, Jr. G&M-5-20-1/2 5.4687
Virginia Sherrill Potter 16.4063
Bivins A-166 Jewell E. Park, Independent Executrix
of the Estate of David Ayers Park, Jr. H&TC-46-106 2.2461
Virginia Sherrill Potter 6.7383
Bivins G-1 Exxon Corporation H&TC-46-93 32.9381
& Bivins 9-R Moore
Bivins H-1 Exxon Corporation H&TC-46-95 24.9415
Moore
Sanford A-3 PanEastern Exploration Co. AB&M-3-9 12.5000
Carson
Bivins 75R Coastal Oil & Gas Corporation H&TC-46-95 21.8234
Exxon Corporation Moore 3.1177
<PAGE>
EXHIBIT "C"
Accounting Procedure
Attached to and made a part of that certain Operating Agreement by and
between MESA OPERATING LIMITED PARTNERSHIP, as Operator, and COLORADO
INTERSTATE GAS COMPANY, as Nonoperator, and dated
January 8, 1988.
---------------
I. GENERAL PROVISIONS
1.1 Definitions. As used in this Accounting Procedure, the
-----------
following words and terms shall have the following meanings:
"Acidize" shall mean a technique for increasing the production from a
well by introducing acid into the well under pressure in order to
enlarge and reopen pores in producing formations.
"Administrative Fee" shall mean the Authorized Payments and Charges
which CIG will charge and collect from Mesa.
"AFE" shall mean an authorization for expenditure.
"Allowable Costs" shall mean those costs and expenses listed and
described in paragraph 2.1 of this Accounting Procedure which Mesa is
authorized to use in computing its "Operations and Maintenance Fee."
Allowable Costs do not include "Capital Expenditures" as that term is
defined below.
"Authorized Payments and Charges" shall mean those payments and
charges listed and described in paragraph 3.1 of this Accounting
Procedure which CIG is authorized to use in computing its
"Administrative Fee."
"British Thermal Unit" means the amount of heat required to raise the
temperature of one pound of water one degree Fahrenheit at 60 degrees
Fahrenheit.
"Capital Expenditures" shall mean all monies expended for all projects
undertaken after January 1, 1990, for the drilling, redrilling,
repair, deepening, Reworking, Acidizing, Frac or other stimulation of
any well subject to the Operating Agreement (except for the costs,
expenses and liabilities excluded from such treatment in Article VI of
the Operating Agreement), or any other projects clearly discernible as
a fixed asset which are required for the development and operation of
the leases subject to the Operating Agreement and which are reasonably
estimated to require an expenditure in excess of $25,000.
"CIG" shall mean Colorado Interstate Gas Company, and/or its successor
in interest under the "B" Contract.
"Contract Area" shall mean all of the Gas Leases (as defined below)
intended to be operated for gas purposes under the Operating
Agreement.
"Controllable Material" shall mean Material which at the time is so
classified in the Material Classification Manual as most recently
recommended by the Council of Petroleum Accountants Societies of North
America.
"COPAS" shall mean the Council of Petroleum Accountants Societies of
North America.
"Exploratory Well" shall mean a well drilled to test a geologic zone
or formation the depth of which is below mean sea level.
"First Level Supervisors" shall mean those employees whose primary
functions in operation under the Operating Agreement is the direct
supervision of other employees and/or contract labor directly employed
on wells subject to the Operating Agreement in a field operating
capacity.
"Frac" shall mean an operation designed to crack or break up
formations which contain Oil and gas by pumping liquids and/or gases
with proppants into the formation under high pressure, in order to
increase the formation's Permeability and to achieve greater
production.
"Gas" shall mean natural gas and all other gaseous hydrocarbons
produced therewith.
"Gross Heating Value," when applied to a cubic foot of gas, means the
number of British thermal units produced by combustion, at a constant
pressure, of the amount of gas which would occupy a volume of one
cubic foot at a temperature of 60 degrees Fahrenheit if saturated with
water vapor and under a pressure equivalent to that of 30 inches of
mercury at 32 degrees Fahrenheit and under standard gravitational
force (980.665 c.m. per sec.) with air of the same temperature and
pressure as the gas, when the products of combustion are cooled to the
initial temperature of gas and air and when the water formed by
combustion is condensed to the liquid state.
"Lease", or "Gas Lease" shall mean any one or more of the gas leases
now or hereafter subject to the "B" Contract on which one or more of
the wells listed and described on Exhibit "All are located, or which
are included in the proration unit for any such well or wells.
"Material" shall mean personal property, equipment or supplies
acquired or held for use on the wells subject to the Operating
Agreement.
"Mesa" shall mean Mesa Operating Limited Partnership and/or its
successor in interest under the "B" Contract.
"Operations and Maintenance Fee" shall mean the charges which Mesa
will be authorized to charge and collect from CIG for performance of
its duties as Operator under the Operating Agreement.
"Personal Expenses" shall mean travel and other reasonable
reimbursable expenses of a party's employees incurred in connection
with operations on the wells subject to the Operating Agreement.
"Proration unit" shall mean the acreage assigned to a well for the
purpose of allocating allowable gas production thereto by order or
rule of the Texas Railroad Commission, or any other state or federal
body having authority.
"Replacement Well" shall mean any gas well drilled on a Gas Lease
subject to the Operating Agreement to replace an existing gas well
which is accepted by the Railroad Commission of Texas as a replacement
for such well.
"Rework" or "Reworking" shall mean any operation performed on a well
after it has been completed in an effort to secure production where
there has been none, to restore production that has ceased, or to
increase production. Cleaning out a well bore that has silted up is a
typical Reworking operation. "Reworks" shall include deepening of an
existing well and Side Tracking if the resulting well is to be
completed in a zone or formation the depth of which is above mean sea
level.
"Side Tracking" means a drilling operation involving the use of a
portion of an existing well bore to drill a second hole, resulting in
a well that is partly old and partly new. Such an operation may be
treated hereunder as an "Exploratory Well" if the objective depth of
said well satisfies the definition for Exploratory Well contained in
Article 1.
"Technical Employees" shall mean those employees which have special
and specific engineering, geological or other professional skills, and
whose primary function in operations is the handling of specific
operating conditions and problems for the benefit of the wells subject
to the Operating Agreement.
1.2 Statements and Billings.
-----------------------
1.2.1 Mesa shall bill CIG on or before the twentieth day of the month
following the month of production for its Operations and Maintenance Fee.
1.2.2 CIG shall bill Mesa on or before the twentieth day of the month
following the month of production for its Administrative Fee.
1.2.3 Costs Of Capital Expenditures will be billed monthly.
1.2.4 All such bills will be accompanied by statements which identify
the AFE, and the well, lease or facility on which the charges being billed
were incurred; and all charges and credits will be summarized by
appropriate classifications of investment and expense except that items of
Controllable Material and unusual charges and credits shall be separately
identified and fully described in detail.
1.3 Payments. All bills are to be paid within fifteen (15) days after
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receipt. If the obligations prescribed in preceding Section 1.2 above have
been satisfied and payment is not made within such time, the unpaid balance
shall bear interest monthly at a rate equal to the sum of the prime rate in
effect at Texas Commerce Bank in Amarillo on the first day of the month in
which delinquency occurs plus one percent, or the maximum contract rate
permitted by the applicable usury laws in the State of Texas, whichever is
the lesser, Plus attorneys fees, court costs, and other costs in connection
with the collection of unpaid amounts.
1.4 Adjustments. Payment of any such bills shall not prejudice the
-----------
right of either party to protest or question the correctness thereof;
provided, however, that all bills and statements rendered hereunder during
any calendar year shall conclusively be presumed to be true and correct
after twenty-four (24) months following the end of any such calendar year,
unless within the said twenty-four month period the recipient of the bill
takes written exception thereto and makes Claim on the other party for
adjustment provided, however, that the provisions of this paragraph shall
not prevent:
(a) refunds from Mesa if any portion of the Operations and
Maintenance Fee or costs of Capital Expenditures billed to CIG are
disallowed by the Federal Energy Regulatory Commission, or its successor
agency; and
(b) additional appropriate billings to Mesa for any royalties,
overriding royalties, production related payments, rentals, shut-in well
payments or minimum royalties determined to have been due previously and
paid following said twenty-four month period; and
(c) adjustments resulting from a physical inventory of controllable
material as provided in Article VI.
1.5 Audits. Either party hereto shall have the right, upon notice in
writing to the other, to audit the other's accounts and records relating to
operations under the Operating Agreement to which this Accounting Procedure
is attached, and to examine the data supporting the charges billed by such
party for any calendar year within the 24-month period following the end of
such calendar year; provided, however, that the making of such an audit
shall not extend the time for the taking of written exception to and the
adjustments of accounts as provided for in paragraph 1.4 above. Both
parties shall make every reasonable effort to conduct audits in a manner
which will result in a minimum of inconvenience to the other party.
Neither party shall bear any portion of the other party's audit costs
incurred under this paragraph unless agreed to by the other party; and the
party undergoing the audit shall reply in writing to an audit report within
180 days of receipt of such report.
II. OPERATIONS AND MAINTENANCE FEE
2.1 Allowable Costs. Mesa is hereby authorized to include the
following items in the computation of its Operations and Maintenance Fee:
2.1.1 Ecological and Environmental
Costs incurred for the benefit of the leases and wells subject to the
Operating Agreement to which this Accounting Procedure is attached as
a result of governmental or regulatory requirements to satisfy
environmental considerations applicable to such leases and wells.
Such costs may include surveys of an ecological or archaeological
nature and pollution control procedures as required by any applicable
laws and regulations.
2.1.2 Labor
A. (1) Salaries and wages of Mesa's field employees directly employed
in the conduct of operations on wells subject to the Operating
Agreement.
(2) Salaries of First Level Supervisors in the field.
(3) Salaries and Wages of Technical Employees directly employed
on wells subject to the Operating Agreement, if such charges
are excluded from the overhead rates in Section 2.2 below.
(4) Salaries and wages of Technical Employees either temporarily
or permanently assigned to and directly employed in the
operation of wells subject to the Operating Agreement if such
charges are excluded from the overhead rates in Section 2.2
below.
(5) Salaries and wages of Technic al Employees either temporarily
or permanently assigned to and directly employed in
preparation of producer nominations or in well scheduling if
such charges are excluded from the overhead rates in Section
2.2 below.
B. Mesa's cost of holiday, vacation, sickness and disability benefits
and other customary allowances paid to employees whose salaries
and Wages are authorized to be charged under subparagraph A above.
Such costs under this subparagraph B will be charged on (i) a
"when and as paid basis" or (ii) a percentage assessment on the
amount of salaries and wages authorized to be charged under
subparagraph A above. if percentage assessment is used, the rate
shall be based on Mesa's recent calendar year cost experience.
C. Expenditures made pursuant to assessments imposed by governmental
authority which are applicable to those Mesa costs which are
chargeable under subparagraphs A and B above.
D. Personal Expenses of those employees whose salaries and wages are
chargeable under subparagraph A above.
2.1.3 Employee Benefits
Mesa's current costs of established plans for employee group life
insurance, hospitalization, pension, retirement, stock purchase,
thrift, bonus and other benefit plans of a like nature, applicable to
Mesa's labor costs as herein authorized under paragraphs 2.1.2.A and
2.1.2.B above shall be Mesa's actual cost not to exceed the percentage
most recently recommended by COPAS.
2.1.4 Transportation
Transportation of employees and Material necessary for operations
under the Operating Agreement subject to the following limitations:
A. If Material is moved to the jobsite from Mesa's warehouse or from
other properties, no charge shall be Made for a distance greater
than the distance from the nearest reliable supply store or
railway receiving point where like Material is normally available
unless agreed to by the parties.
B. If surplus Material is moved to Mesa's warehouse or other storage
point, no charge shall be made for a distance greater than the
distance to the nearest reliable supply store or railway receiving
point unless agreed to by the parties. No charge shall be made
for moving Material to other properties belonging to Mesa or to
any subsidiary or affiliate unless agreed to by the parties.
C. In the application of paragraphs A. and B. above, the option to
equalize or charge actual trucking cost is available when the
actual charge is $400 or less excluding accessorial charges. The
$400 will be adjusted to the amount most recently recommended by
COPAS.
D. No charge shall be made for transportation of Mesa's
representatives on the Engineering Committee (Article XV,
Operating Agreement).
2.1.5 Services
The cost of contract services, equipment and utilities provided by
outside sources, except as otherwise provided for legal services in
paragraph 2.1.8 hereinbelow or as excluded under Section 2.2 below.
The cost of professional consulting services and contract services of
technical personnel directly engaged in operations on wells subject to
the Operating Agreement, if such charges are excluded from the
overhead rates in Section 2.2 below. The cost of professional
consulting services or contract services of technical personnel not
directly engaged in operations on such wells shall not be charged
unless previously agreed to by the parties hereto.
2.1.6 Equipment and Facilities Furnished by Mesa
Mesa shall charge CIG for the use of Mesa's owned equipment and
facilities at rates commensurate with costs of ownership and
operation. Such rates shall include costs of maintenance, repairs,
other operating expense, insurance, taxes, depreciation and interest
on gross investment less accumulated depreciation not to exceed twelve
percent (12%) per annum. Such rates shall not exceed average
commercial rates currently prevailing in the immediate area of the Gas
Leases subject to the Operating Agreement.
2.1.7 Damages and Losses
Except as otherwise provided in Article X of the Operating Agreement
to which this Accounting Procedure is attached, all costs or expenses
necessary for the repair of the wells subject to the Operating
Agreement which are made necessary because of damages or losses
incurred by fire, flood, storm, theft, accident or other cause, except
those resulting from Mesa's gross negligence or willful misconduct.
Mesa shall furnish CIG written notice of damages or losses incurred as
soon as practicable after a report thereof has been received by Mesa.
2.1.8 Legal Expense
Except as otherwise provided in Article X of the Operating Agreement
to which this Accounting Procedure is attached, the costs and expenses
of handling, investigating and settling litigation or claims, payment
of judgments and amounts paid for settlement of claims incurred in
or resulting from operations under the Operating Agreement or
necessary to protect or recover the Gas Leases, and the costs and
expenses incurred in connection with hearings and other matters before
governmental bodies and/or regulatory agencies and costs and expenses
incurred in examining and curing title; provided, however, that there
shall be no charge for Mesa's in-house legal staff.
2.1.9 Insurance
Net premiums paid for insurance required to be carried for operations
under the Operating Agreement as shown in Exhibit "D" thereto for the
protection of both the parties. In the event that Mesa elects to act
as a self-insurer under the workers' compensation laws of the State of
Texas, it may include the risk under its self-insurance program and in
that event, it shall include a charge at its actual cost not to exceed
the rates authorized or recommended by COPAS.
2.1.10 Communications
Costs of acquiring, leasing, installing, operating, repairing and
maintaining communication systems, including radio and microwave
facilities directly serving wells subject to the Operating Agreement.
2.1.11 Other Expenditures
Any other expenditure not covered or dealt with in the foregoing
provisions of this Section 2.1 and Section 2.2 and which is of direct
benefit to the Contract Area and is incurred by Mesa in the necessary
and proper conduct of operations on the Contract Area.
2.2 Overhead. As compensation for administration, for maintenance and for
--------
operation of the wells subject to the Operating Agreement, for supervision
of additional drilling or Reworks, and for administrative, supervisory and
office services and warehousing costs, Mesa shall include with its other
Allowable Costs (which are allocated to CIG based on the ratio of the
volume of gas taken by CIG for redelivery to third parties to the total
volume of gas delivered to CIG from wells subject to the Operating
Agreement) a rate of 3.5 cents per Mcf. Unless otherwise agreed to by the
parties, such charge shall be in lieu of costs and expenses of all offices
and salaries or wages plus applicable burdens and expenses of all
personnel; provided, however:
The salaries, wages and Personal Expenses of Technical Employees
and/or the cost of professional consulting services and contract
services of technical personnel directly employed on wells
subject to the Operating Agreement ( ) shall ( X ) shall not
--- ---
be covered by the overhead rates.
The salaries, wages and Personal Expenses of Technical Employees
and/or costs of professional consultant services and contract
services of technical personnel either temporarily or permanently
assigned to and directly employed in operation of wells subject
to the Operating Agreement ( X ) shall ( ) shall not be covered
--- ---
by the overhead rates.
The salaries, wages and Personal Expenses of Technical Employees
directly employed in the nomination and dispatching of gas under
section 5.3 of the Operating Agreement to which this Accounting
Procedure is attached ( ) shall ( X ) shall not be covered by
--- ---
the overhead rates.
2.3 Adjustments to Overhead Rate. The foregoing rate shall be
----------------------------
adjusted as of the first day of April, 1991 and each April 1 thereafter
following the effective date of the Operating Agreement to which this
Accounting Procedure is attached. The adjustment shall be computed by
multiplying the rate currently in use by the percentage increase or
decrease in the average weekly earnings of Crude Petroleum and Gas
Production Workers for the last calendar year compared to the calendar year
preceding as shown by the index of average weekly earnings of Crude
Petroleum and Gas Production Workers as published by the United States
Department of Labor, Bureau of Labor Statistics. The adjusted rate shall
be the rates currently in use, plus or minus the computed adjustment.
2.4 Computation of Operations and Maintenance Fee. The rate at which
---------------------------------------------
Mesa may recover that portion of its Allowable Costs and overhead, as
provided above, which is due from CIG will be computed as follows: For all
natural gas produced from wells subject to the Operating Agreement and
delivered into CIG's gathering system for redelivery to third parties
(other than Mesa) on and after January 1, 1990, Mesa shall be entitled to
bill CIG at a rate per Mcf determined by dividing the total Allowable Costs
actually incurred by Mesa in the preceding year plus the overhead charge
described above by the total volume of gas which is estimated to be
produced and delivered from such wells into CIG's gathering system in the
current year. CIG shall then pay Mesa at this rate per Mcf for gas
delivered to CIG for redelivery to parties other than Mesa until the rate
is redetermined as provided in paragraph 2.4.2 below.
2.4.1 By November 30 of each year, Mesa will make an estimate of the
total Allowable Costs (including overhead) to be incurred during such year
and furnish this estimate to CIG as the cost basis for the succeeding year.
For the year 1990, Mesa shall make such estimate as soon as practicable
after the effective date of the Operating Agreement. Also on or before
November 30 of each year, the Engineering Committee shall make an estimate
of the total volume of gas to be produced and delivered from such wells
during the succeeding year, and thereby determine the rate per Mcf to be
billed to CIG as the Operations and Maintenance Fee for the succeeding
year. For the year 1990, the estimate shall be the same as the volume of
gas delivered in 1989, unless by January 20, 1990, the Engineering
Committee agrees to another figure.
2.4.2 On or about April 30 of the succeeding year, Mesa shall furnish
an accounting to determine the Operations and Maintenance Fee for the
previous calendar year based on the actual total of Allowable Costs and
actual total volume of gas produced and delivered from wells subject to the
Operating Agreement. All necessary adjustments to billings or payments
shall be made within thirty (30) days of receipt of the actual totals by
CIG.
2.5 Catastrophe Overhead. To compensate Mesa for overhead costs
--------------------
incurred in the event of expenditures resulting from a single occurrence
due to oil spill, blowout, explosion, fire, storm, tornado or other
catastrophes as agreed to by the parties, which are necessary to return
wells subject to the Operating Agreement to the condition that existed
prior to the event causing the expenditures, Mesa shall charge the same
rates as set forth for Capital Expenditures (Article IV) hereinbelow.
III. ADMINISTRATIVE FEE
3.1 Authorized Payments and Charges. CIG is hereby authorized to
-------------------------------
include the following items to the extent indicated in the computation of
its Administrative Fee:
A. Royalties, Overriding Royalties and Production Related Payments
All leasehold royalties, overriding royalties and other payments
out of production from wells subject to the Operating Agreement.
Those certain royalty Payments under paragraph 2 (a) of that
certain "Compromise and Settlement Agreement" dated December 31,
1981, by and between Amarillo Oil Company ("AOC"), CIG and the
royalty owners identified as "Lessor" therein and the
contemporaneous letter agreement between AOC and CIG shall be
billed in full to Mesa without allocation.
B. Rentals, Shut-In Well Payments and Minimum Royalties
All rentals, shut-in well payments and minimum royalties which may
be required under the terms of any Gas Lease subject to the
Operating Agreement.
C. Taxes
All property taxes assessed or levied (i) upon wells subject to
the Operating Agreement, (ii) upon any leases subject to the
Operating Agreement and/or (iii) upon the gas reserves associated
with such leases; all production or severance taxes levied or
assessed at the wellhead on the value of gas produced from such
wells; and all other taxes of a similar nature now in force or
enacted in the future.
D. Depreciation and Return
Depreciation on the original cost of any Capital Expenditures
undertaken after January 1, 1990, at the applicable depreciation
rate computed on a unit of production basis based on remaining
recoverable reserves attributable to the Contract Area; and a
return of twenty percent (20%) on net book value (original cost
less accumulated depreciation) of the Capital Expenditures.
3.2 Computation of Administrative Fee. The rate at which CIG may
---------------------------------
recover that portion of its Authorized Payments and Charges, as provided
above, which is due from Mesa will be computed as follows: For all natural
gas produced from wells subject to the Operating Agreement and delivered
into CIG's gathering system for redelivery to Mesa on and after January 1,
1990, CIG shall be entitled to bill Mesa at a rate per Mcf determined by
dividing the total Authorized Payments and Charges actually incurred by CIG
in the preceding year by the total volume of gas which is estimated to be
produced and delivered from such wells into CIG's gathering system in the
current year. Mesa shall then pay CIG at this rate per Mcf for all gas
redelivered to Mesa by CIG until the rate is redetermined as provided in
paragraph 3.2.2 below.
3.2.1 By November 30 of each year, CIG will make an estimate of the
total Authorized Payments and Charges to be incurred during such year and
furnish this estimate to Mesa as the cost basis for the succeeding year.
For the year 1990, CIG shall make such estimate as soon as practicable
after the effective date of the Operating Agreement to which this
Accounting Procedure is attached. Also on or before November 30 of each
year, the Engineering Committee shall make an estimate of the total volume
of gas to be produced and delivered from such wells during the succeeding
year, and thereby determine the rate per Mcf to be billed to Mesa as the
Administrative Fee for the succeeding year. For the year 1990, the
estimate shall be the same as the volume of gas delivered in 1989, unless
the Engineering Committee agrees to another figure by January 20, 1990.
3.2.2 On or about April 30 of the succeeding year, CIG shall furnish
an accounting to determine the Administrative Fee for the previous calendar
year based on the actual total of Authorized Payments and Charges and
actual total volume of gas produced and delivered from wells subject to
the Operating Agreement. All necessary adjustments to billings or payments
shall be made within thirty (30) days of receipt of the actual totals by
Mesa.
IV. CAPITAL EXPENDITURES
4.1 Definition. Capital Expenditures shall include expenditures on
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all projects undertaken after January 1, 1990, for the drilling,
redrilling, repair, deepening, Reworking, Acidizing, Frac or other
stimulation of any well subject to the Operating Agreement (except for the
costs, expense and liabilities excluded from such treatment in Article VI
of the Operating Agreement), or any other projects clearly discernible as a
fixed asset which are required for the development and operation of the
leases subject to the Operating Agreement and which are reasonably
estimated to require an expenditure in excess of $25,000.
4.2 Not Part of Operations and Maintenance Fee. Capital Expenditures
------------------------------------------
and overhead as provided below shall be billed to CIG separate and apart
from the Operations and Maintenance Fee and shall not be subject to
allocation based on the respective volumes Of gas taken by Mesa and CIG.
All such costs shall be treated by CIG as capital expenditures, and all
billings from Mesa relating thereto will be accompanied by statements which
identify the AFE, and the well, lease or facility on which the charges were
incurred. Such billings will be made ona monthly basis.
4.3 Overhead. To compensate Mesa for its overhead costs, Mesa shall
--------
either negotiate a rate prior to the beginning of such operation or
construction, or charge CIG for overhead based on the following rates:
5% of the first $100,000, or total cost if less, plus
---
3% of costs in excess of $100,000, but less than $1,000,000, plus
---
2% of costs in excess of $1,000,000.
---
Total cost shall mean the gross cost of any one project. For the
purpose of this paragraph, the component parts of a single project shall
not be treated separately and the cost of drilling and workover wells and
of artificial lift equipment shall be included.
V. PRICING OF MATERIAL PURCHASES, TRANSFERS AND DISPOSITIONS
Mesa is responsible for Material, defined to mean all personal
property, equipment or supplies acquired or held for use on the wells
subject to the Operating Agreement, and Mesa shall make proper and timely
charges and credits for all Material movement. Mesa shall provide all
Material for use on such wells, and make timely disposition of idle and/or
surplus Material.
5.1 General. Only such Material shall be purchased, or transferred,
-------
for use on wells subject to the Operating Agreement as is reasonably
practical and consistent with efficient and economical operations.
5.2 Purchases. Material purchased shall be charged at the price paid
---------
by Mesa after deduction of all discounts received. In case of Material
found to be defective or returned to vendor for any other reasons, credit
shall be passed to CIG when the adjustment has been received by Mesa.
5.3 Transfers and Dispositions. Material furnished for operation of
--------------------------
the wells subject to the Operating Agreement and Material transferred from
such wells or disposed of by Mesa, unless otherwise agreed to by the
parties, shall be priced on the following basis exclusive of cash
discounts:
A. New Material
(1) Tubular Goods Other than Line Pipe
(a) Tubular goods, sized 2 3/8 inches 00 and larger, except
line pipe, shall be priced at Eastern mill published
carload base prices effective as of date of movement
plus transportation cost using the 80,000 pound carload
weight basis to the railway receiving point nearest the
Contract Area for which published rail rates for tubular
goods exist. If the 80,000 pound rail rate is not
offered, the 70,000 pound or 90,000 pound rail rate may
be used. Freight charges for tubing will be calculated
from Lorain, Ohio and casing from Youngstown, Ohio.
(b) For grades which are special to one mill only, prices
shall be computed at the mill base of that mill plus
transportation cost from that mill to the railway
receiving point nearest the Contract Area as provided
above in paragraph 5 3.A(l)(a). For transportation cost
from points other than eastern mills, the 30,000 pound
Oil Field Haulers Association interstate truck rate
shall be used.
(c) Special end finish tubular goods shall be priced at the
lowest published out-of-stock price, f.o.b. Houston,
Texas, plus transportation cost, using the Oil Field
Haulers Association interstate 30,000 pound truck rate,
to the railway receiving point nearest the Contract
Area.
(d) Macaroni tubing (size less than 2 3/8 inch 00) shall be
priced at the lowest published out-of-stock prices
f.o.b. the supplier plus transportation costs, using the
Oil Field Haulers Association interstate truck rate per
weight of tubing transferred, to the railway receiving
point nearest the Contract Area.
(2) Line Pipe
(a) Line pipe movements (except size 24 inch OD and larger
with walls 3/4 inch and over) 30,000 pounds or more
shall be priced under provisions of tubular goods
pricing in paragraph A(l)(a) hereinabove. Freight
charges shall be calculated from Lorain, Ohio.
(b) Line pipe movements (except size 24 inch 00 and
larger with walls 3/4 inch and over) less than 30,000
pounds shall be priced at Eastern mill published carload
base prices effective as of date of shipment, plus 20
percent, plus transportation costs based on freight
rates as set forth under provisions of tubular goods
pricing in Paragraph A(l)(a) hereinabove. Freight
charges shall be calculated from Lorain, Ohio.
(c) Line pipe 24 inch 00 and over and 3/4 inch wall and
larger shall be priced f.o.b. the point of manufacture
at current new published prices plus transportation cost
to the railway receiving point nearest the Contract
Area.
(d) Line pipe, including fabricated line pipe, drive pipe
and conduit not listed on published price lists shall be
priced at quoted prices plus freight to the railway
receiving point nearest the Contract Area or at prices
agreed to by the parties.
(3) Other Material shall be priced at the current new price, in
effect at date of movement, as listed by a reliable supply
store nearest the Contract Area, or point of manufacture,
plus transportation costs, if applicable, to the railway
receiving point nearest the Contract Area.
(4) Unused new Material, except tubular goods, moved from the
Contract Area shall be priced at the current new price, in
effect on date of movement, dS listed by a reliable Supply
store nearest the Contract Area, or point of manufacture,
plus transportation costs, if applicable, to the railway
receiving point nearest the Contract Area. Unused new
tubulars will be priced as provided above in paragraph
5.3.A(l) and 5.3.A(2) above.
B. Good Used Material (Condition B) - Material in sound and
serviceable condition and suitable for reuse without reconditioning
(1) Material moved to the Contract Area
At seventy-five percent (75%) of current new price as
determined by paragraph 5.3.A above.
(2) Material used on and moved from the Contract Area
(a) At seventyfive percent (75%) of current new price as
determined by paragraph 5.3.A above, if material was
originally charged to CIG as new Material, or
(b) At sixty-five percent (65%) of current new price, as
determined by paragraph 5.3.A above, if Material was
originally charged to CIG as used Material.
(3) Material not used on and moved from the Contract Area
At seventy-five percent (75%) of current new price as
determined by paragraph 5.3.A above.
The cost of reconditioning, if any, shall be deducted from the proceeds
received for the property being transferred.
C. Other Used Material
(1) Condition C
Material which is not in sound and serviceable condition and
not suitable for its original function until after
reconditioning shall be priced at fifty percent (50%) of
current new price as determined by paragraph 5.3.A above.
The cost of reconditioning shall be deducted from the
proceeds received for the Material being transferred,
provided Condition C value plus cost of reconditioning does
not exceed Condition B value.
(2) Condition D
Material, excluding junk, no longer suitable for its original
purpose, but usable for some other purpose shall be priced on
a basis commensurate with its use. Mesa may dispose of
Condition D Material under procedures normally used by it
without prior approval of CIG.
(a) Casing, tubing or drill pipe used as line pipe shall be
priced as Grade A and B seamless line pipe of comparable
size and weight. Used casing, tubing or drill pipe
utilized as line pipe shall be priced at used line pipe
prices.
(b) Casing, tubing or drill pipe used as higher pressure
service lines than standard line pipe, e.g., power oil
lines, shall be priced under normal pricing procedures
for casing, tubing or drill pipe. Upset tubular goods
shall be priced on a non upset basis.
(3) Condition E
Junk shall be priced at prevailing prices. Mesa may dispose
of Condition E Material under procedures normally utilized by
it without prior approval of CIG.
D. Obsolete Material
Material which is serviceable and usable for its original
function but condition, and/or value of such Material is not
equivalent to that which would justify a price as provided
above.
Such material shall be priced as agreed to by Mesa and CIG.
E. Pricing Conditions
(1) Loading or unloading costs may be charged at the rate of
twenty-five cent (25 cents) per hundred weight on all
tubular goods movements in lieu of actual loading or
unloading costs sustained at the stocking point. The
above rate shall be adjusted as of the first day of
April each year following January 1, 1991 by the same
percentage increase or decrease used to adjust the
overhead rate as established in paragraph 2.3 above.
Each year, the rate calculated shall be rounded to the
nearest cent and shall be the rate in effect until the
first day of April next year.
(2) Material involving erection costs shall be charged at
applicable percentage of the current knocked-down price
of new Material.
5.4 Warranty of Material Furnished by Mesa. Mesa does not warrant
--------------------------------------
the Material furnished. In case of defective Material, credit
shall not be passed on to CIG until adjustment has been received
by Mesa from the manufacturers or their agents.
VI. INVENTORIES
Mesa shall maintain detailed records of Controllable Material.
6.1 Periodic Inventories, Notice and Representation. Mesa shall take
-----------------------------------------------
inventories of Controllable Material at reasonable intervals. Written
notice of Mesa's intention to take inventory shall be given by Mesa at
least thirty (30) days before any inventory is to begin so that CIG may be
represented when any inventory is taken. Failure of CIG to be represented
at an inventory following receipt of proper notice shall bind CIG to accept
the inventory taken by Mesa.
6.2 Reconciliation and Adjustment of Inventories. Adjustments
--------------------------------------------
resulting from the reconciliation of a physical inventory shall be made
within six months following the taking of the inventory. Inventory
adjustments shall be made by Mesa for overages and shortages, but Mesa
shall be held accountable only for shortages due to lack of reasonable
diligence.
6.3 Special Inventories. A special inventory may be taken whenever
-------------------
there is a change of Operator, and all parties shall be governed by such
inventory.
6.4 Expense of Conducting Inventories. The expense of conducting
---------------------------------
periodic inventories shall not be charged to CIG. The expense of
conducting a special inventory required due to change of Operator shall be
charged to CIG.
<PAGE>
EXHIBIT "D"
Insurance Requirements
Attached to and made a part of Operating Agreement dated January 8, 1988,
by and between MESA OPERATING LIMITED PARTNERSHIP ("Mesa"), as Operator,
and COLORADO INTERSTATE GAS COMPANY ("CIG"), as Nonoperator.
I. Mesa shall at all times while operations are conducted by it on the
Contract Area, carry or cause to be carried and pay for, in accordance
with Exhibit "C" to the Operating Agreement, Worker's Compensation and
Occupational Disease Insurance including Employer's Liability
Insurance covering the employees of Mesa engaged in operations
hereunder in compliance with all applicable State and Federal Laws.
Such policies shall contain underwriters waiver of subrogation in
favor of CIG.
II. Mesa and CIG shall each carry for their own respective interests the
following types and limits of insurance:
(A) Comprehensive General Liability covering operations conducted
hereunder:
Combined Bodily Injury and Property Damage
$1,000,000 per occurrence
$1,000,000 Aggregate
(B) Automobile Liability covering all vehicles owned, non-owned, or hired
and used in connection with operations conducted hereunder:
Combined Bodily Injury and Property Damage
$1,000,000 per occurrence
$1,000,000 Aggregate
III. Each party hereto may acquire at its own expense, any additional
insurance it desires to protect itself. Each such policy shall
provide for underwriters waiver of subrogation in favor of the other
party hereto.
IV. Mesa shall have the right, but not the obligation, to require
satisfactory evidence of insurance or self-insurance from CIG.
V. Mesa shall have the right, but not the obligation, to require
satisfactory evidence of adequate insurance or self-insurance for cost
of control of well and pollution liability from CIG. Mesa shall not
provide this coverage for the benefit of CIG. In the event that CIG
fails to provide evidence of insurance as required herein ("failing
party"), Mesa may, at its sole discretion, provide such insurance for
and at the direct expense of the failing party. Such expense shall be
an Allowable Cost charged and shared as provided in the Accounting
Procedure attached to the Operating Agreement as Exhibit "C." Mesa is
under no obligation to provide such insurance for the party so failing
to provide satisfactory evidence of its own insurance and nothing
contained herein shall be construed to alter the obligations of any
party hereunder.
<PAGE>
EXHIBIT "E"
Attached to and made a part of that certain Operating Agreement
by and between MESA OPERATING LIMITED PARTNERSHIP ("Mesa"), as
Operator, and COLORADO INTERSTATE GAS COMPANY, as Nonoperator, and
dated January 8, 1988.
EQUAL EMPLOYMENT OPPORTUNITY PROVISION
During the performance of this contract, the Operator (meaning and
referring separately to each party hereto) agrees as follows:
1. Mesa will not discriminate against any employee or applicant for
employment because of race, color, religion, sex, or national
origin. Mesa will take affirmative action to ensure that
applicants are employed and that employees are treated during
employment without regard to their race, color, religion, sex, or
national origin. Such action shall include, but not be limited
to, the following: employment, upgrading, demotion, or transfer;
recruitment or recruitment advertising; layoff or termination;
rates of pay or other forms of compensation; and selection for
training, including apprenticeship. Mesa agrees to post in
conspicuous places, available to employees and applicants for
employment, notices to be provided setting forth the provisions of
this nondiscrimination clause.
2. Mesa will, in all solicitations or advertisements for employees
placed by or on behalf of Mesa, state that all qualified
applicants will receive consideration for employment without
regard to race, color, religion, sex, or national origin.
3. Mesa will send to each labor union or representative of workers
with which Mesa has a collective bargaining agreement or other
contract or understanding, a notice to be provided, advising the
said labor union or workers' representatives of Mesa's commitments
under Section 202 of Executive Order 11246 of September 24, 1965,
and shall post copies of the notice in conspicuous places
available to employees and applicants for employment.
4. Mesa will comply with all provisions of Executive Order 11246 of
September 24, 1965, and of the rules, regulations, and relevant
orders of the Secretary of Labor.
5. Mesa will furnish all information and reports required by
Executive Order 11246 of September 24, 1965, and by the rules,
regulations, and orders of the Secretary of Labor, or pursuant
thereto, and will permit access to Mesa's books, records, and
accounts by the administering agency and the Secretary of Labor
for purposes of investigation to ascertain compliance with such
rules, regulations, and orders.
6. In the event of Mesa's noncompliance with the nondiscrimination
clauses of this contract or with any of the said rules,
regulations, or orders, this contract may be canceled, terminated,
or suspended in whole or in part and Mesa may be declared
ineligible for further Government contracts or federally assisted
construction contracts in accordance with procedures authorized in
Executive Order 11246 of September 24, 1965, and such order
sanctions may be imposed and remedies invoked as provided in
Executive Order 11246 of September 24, 1965, or by rule,
regulation, or order of the Secretary of Labor, or as otherwise
provided by law.
7. Mesa will include the provisions of Paragraphs (1) through (7) in
every subcontract or purchase order unless exempted by rules,
regulations, or orders of the Secretary of Labor issued pursuant
to Section 204 of Executive Order 11246 of September 24, 1965, so
that provisions will be binding upon each subcontractor or vendor.
Mesa will take such action with respect to any subcontract or
purchase order as the administering agency may direct as a means
of enforcing
such provisions, including sanctions for noncompliance: Provided,
--------
however, that in the event Mesa becomes involved in, or is
-------
threatened with, litigation with a subcontractor or vendor as a
result of such direction by the administering agency, Mesa may
request the United States to enter into such litigation to
protect the interests of the United States.
Mesa acknowledges that Mesa may be required to file Standard Form 100 (EEO-
1) promulgated jointly by the Office of Federal Contract Compliance, the
Equal Employment Opportunity Commission, and Plans for Progress with the
appropriate agency within 30 days of the date of contract award if such
report has not been filed for the current year and otherwise comply with or
file such other compliance reports as may be required under Executive Order
11246, as amended, and Rules and Regulations adopted thereunder.
Mesa further acknowledges that Mesa may be required to develop a written
affirmative action compliance program as required by the Rules and
Regulations approved by the Secretary of Labor under authority of Executive
Order 11246 and supply each other party hereto with a copy of such program
if so requested.
CERTIFICATION OF NONSEGREGATED FACILITIES
By entering into this contract, Mesa certifies that Mesa does not and will
not maintain or provide for Mesa's employees any segregated facilities at
any of Mesa's establishments and that Mesa does not and will not permit
Mesa's employees to perform their services at any location, under Mesa's
control, where segregated, facilities are maintained. Mesa agrees that a
breach of this certification is a violation of the Equal Opportunity clause
in this contract. As used in this certification, the term "segregated
facilities" means, but is not limited to, any waiting rooms, work areas,
rest rooms and washrooms, restaurants and other eating areas, time clocks,
locker rooms, and other storage or dressing areas, parking lots, drinking
fountains, recreation or entertainment areas, transportation, and housing
facilities provided for employees which are segregated by explicit
directive or are in fact segregated on the basis of race, color, religion,
or national origin, because of habit, local custom, or otherwise. Mesa
further agrees that (except where Mesa has obtained identical
certifications from proposed contractors and subcontractors for specific
time periods) Mesa will obtain identical certifications from proposed
contractors and subcontractors prior to the award of contracts or
subcontracts exceeding $10,000 which are not exempt from the provisions of
the Equal Opportunity clause; that Mesa will retain such certifications in
Mesa's files; and that Mesa will forward the following notice to such
proposed contractors and subcontractors (except where the proposed
contractors or subcontractors have submitted identical certifications for
specific time periods): Notice to prospective contractors and
subcontractors of requirement for certifications of nonsegregated
facilities. A Certificate of Nonsegregated Facilities must be submitted
prior to the award of a contract or subcontract exceeding $10,000 which is
not exempt from the provisions of the Equal Opportunity clause. The
certification may be submitted either for each contract and subcontract or
for all contracts and subcontracts during a period (i.e., quarterly,
semiannually, or annually).
AGREEMENT OF COMPROMISE AND SETTLEMENT
--------------------------------------
This AGREEMENT OF COMPROMISE AND SETTLEMENT (hereinafter referred to
as "this Agreement") is made and entered into this 29th day of May, 1987,
by and between MESA OPERATING LIMITED PARTNERSHIP, a limited partnership
organized under the laws of the State of Delaware with its principal place
of business in Amarillo, Texas (hereinafter referred to as "Mesa"), and
COLORADO INTERSTATE GAS COMPANY, a corporation organized under the laws of
the State of Delaware with its principal place of business in Colorado
Springs, Colorado (hereinafter referred to as "CIG").
RECITALS
A. CIG and Mesa are the current parties in interest to an agreement,
as amended and supplemented, initially entered on January 3, 1928, between
Canadian River Gas Company and Amarillo Oil Company, which is commonly
referred to as the "B" Contract.
B. CIG is operator of the wells committed under the "B" Contract and
is obligated to deliver certain volumes of natural gas to Mesa under that
agreement. Mesa has a priority right to receive such gas as is required by
Mesa to supply any customers located in the City of Amarillo or its
environs. CIG is entitled to receive that natural gas produced from such
wells in excess of those volumes taken by Mesa. The rights of the parties
have been modified by the terms of an Uncontested Settlement Agreement
approved by the Federal Energy Regulatory Commission.
C. Disputes have arisen regarding the actions of CIG and Mesa under
the "B" Contract, with the result that litigation has been instituted in
Texas and Colorado. The parties now wish to resolve their disputes, dismiss
all pending litigation between them, and establish an overall framework for
future operations and procedures which is intended to mitigate the
possibility of prospective disputes arising.
AGREEMENT
For and in consideration of the premises and mutual covenants
contained herein and of the instruments attached as Exhibits A, B, C, D, E,
and Fhereto, the parties, intending to be legally bound hereby, agree as
follows:
ARTICLE I.
DEFINITIONS
-----------
The terms defined in this Article I shall, for all purposes of this
Agreement, have the meanings specified, unless otherwise specified or the
context otherwise requires.
Amarillo Litigation:
- -------------------
The term "Amarillo Litigation" shall mean that lawsuit instituted by
Mesa against CIG, and all causes of action asserted therein, whether as a
claim or counterclaim, in the District Court of Potter County, Texas, 251st
Judicial District, Cause No. 68002C, and subsequently removed to the United
States District Court for the Northern District of Texas, Civil Action No.
2-86-0300.
"B" Contract:
- ------------
The "'B' Contract" is that agreement, as amended and supplemented,
entered on January 3, 1928, between Canadian River Gas Company, as
predecessor in interest to CIG, and Amarillo Oil Company, as predecessor in
interest to Mesa.
Colorado Springs Litigation:
- ---------------------------
The term "Colorado Springs Litigation" shall mean that lawsuit
instituted by CIG against Mesa, and all causes of action asserted therein,
whether as a claim or counterclaim, in the District Court of El Paso
County, Colorado, Civil Action No. 86 CV 5573.
FERC:
- ----
"FERC" shall mean the Federal Energy Regulatory Commission; its
predecessor agency, the Federal Power Commission; and any successor agency
or other authority succeeding to its regulatory powers.
Fiscal Year:
- -----------
The term "fiscal year" shall mean the 12 month period commencing
October 1 of any year.
Settlement Date:
- ---------------
The term "Settlement Date" shall mean the data upon which this
Agreement shall become effective, which shall be August 1, 1987, or such
other business day in the State of Texas selected by mutual agreement in
writing of Mesa and CIG.
Staff:
- -----
The term "Staff" shall mean the Staff of the FERC.
Uncontested Settlement Agreement:
- --------------------------------
The term "Uncontested Settlement Agreement" shall mean the Uncontested
Settlement Agreement on Reserved Issues submitted to the FERC by the
parties and the Staff in Docket No. RP79-59, Colorado Interstate Gas
-----------------------
Company, on or about December 31, 1980, and accepted and approved without
- --------
change or modification by the FERC on March 4, 1981.
ARTICLE II.
PROVISIONS WITH RESPECT TO UNCONTESTED SETTLEMENT AGREEMENT
-----------------------------------------------------------
Section 2.01 Withdrawal Rights.
- ------------------------------
Mesa and CIG agree not to withdraw from the Uncontested Settlement
Agreement prior to January 1, 1990 and to continue to be bound by the terms
and conditions of the Uncontested Settlement Agreement until that date,
unless
(a) Staff or any other party withdraws
from the Uncontested Settlement
Agreement, or
(b) the FERC issues an order which
materially modifies the Uncontested
Settlement Agreement.
Section 2.02 Limitation on Daily Takes.
- --------------------------------------
CIG may exercise its right under Paragraph 2.2 of the Uncontested
Settlement Agreement to request that Mesa limit its daily takes from CIG to
a volume not to exceed 70,000 Mcf on any day during the period from the
Settlement Date until the Uncontested Settlement Agreement is terminated
or, if terminated prior to September 30, 1988, 80,000 Mcf on any day
during the period from such date of termination until September 30, 1988.
Subject to Paragraph 2.1 of the Uncontested Settlement Agreement, CIG will
utilize all reasonable efforts to deliver to Mesa additional volumes up to
a total delivery of 90,000 Mcf on any day such deliveries are requested by
Mesa. CIG has no obligation to install additional facilities in order to
deliver more than 70,000 Mcf on any such day. However, the parties
recognize that CIG will, irrespective of this Agreement, install
approximately $400,000 worth of pigging facilities. Mesa shall have the
option, if it desires the delivery of additional volumes, to install any
additional compression facilities at the inlet side of the Fain Processing
Plant, or such other location as may be mutually agreed, necessary to
deliver such additional volumes. Whenever deficiencies in deliveries
based upon such requests by Mesa appear to be occurring on an unacceptable
frequency in Mesa's opinion, CIG agrees to meet with Mesa upon Mesa's
request to determine whether there are feasible and economic methods
and/or changes to improve deliveries and to implement, in good faith and
with diligence, such methods which would permit 90,000 Mcf per day to be
delivered to Mesa. Deliveries of such additional volumes shall not affect
the obligation of CIG to deliver to Mesa the lesser of the fiscal year
requirements of Amarillo and environs as per the "B" Contract or 25.55 Bcf
so long as the Uncontested Settlement Agreement remains in effect.
Section 2.03 Expression of Parties' Intent.
- ------------------------------------------
Mesa and CIG hereby affirm that it is their intent that nothing
contained in this Article II or elsewhere in this Agreement is to be
construed as a material modification of the Uncontested Settlement
Agreement.
ARTICLE III.
AMENDMENTS TO THE "B" CONTRACT
------------------------------
Section 3.01 The Amendment.
- --------------------------
Mesa and CIG agree that, concurrently with the execution of this
Agreement, the parties shall execute amendment to the "B" Contract in the
form attached hereto a Exhibit A to become effective on January 1, 1990.
ARTICLE IV.
BALANCING AGREEMENT.
-------------------
Section 4.01. Extension of Balancing Arrangements.
- ------------ -----------------------------------
CIG and Mesa agree that the letter agreement dated March 6, 1981,
between CIG and Amarillo Oil Company, regarding the delivery of gas by CIG
to Mesa, as successor to Amarillo Oil Company, under the "B" Contract
shall not terminate at the time the Uncontested Settlement Agreement
terminates, but shall be terminable by either party effective at the end
of a fiscal year after the termination of the Uncontested Settlement
Agreement upon at least ninety (90) days written notice given prior to the
commencement of the next fiscal year.
ARTICLE V.
GATHERING AGREEMENT.
-------------------
Section 5.01. Gathering Issues.
- ------------ ----------------
Mesa and CIG agree that, concurrently with the execution of this
Agreement, the parties shall execute an agreement in the form attached
hereto as Exhibit B to become, effective on the Settlement Date.
ARTICLE VI.
OPERATING AGREEMENT
-------------------
Section 6.01. Operations.
- ------------ ----------
Mesa and CIG agree that Mesa shall become operator of the wells
committed to the "B" Contract on January 1, 1990. In this regard, Mesa
and CIG agree to enter into good faith negotiations as soon as reasonably
possible after the execution by the parties of this Agreement, to reach
agreement as to the terms and conditions which should be contained within
an operating agreement and accounting procedure, to be effective January
1, 1990. Mesa and CIG shall cooperate fully in such project so that an
operating agreement and accounting procedure can be completed no later
than September 1, 1987 As to the operating agreement and accounting
procedure, Mesa and CIG agree that the A.A.P.L. Form 610-1982 Model Form
Operating Agreement, and the Copas 1984 Onshore Accounting Procedure for
Joint Operations shall be utilized as a guideline by the parties as the
"forms" within which the mutual agreement of the parties shall be
incorporated. However, both Mesa and CIG acknowledge that each form shall
be modified or amended to contain such provision as the parties shall
mutually deem necessary including, but not limited to, the following
items:
(1) The delivery to Mesa of all necessary production data, well files
and records incident to all producing wells.
(2) The responsibility to maintain the oil and gas leases by the
payment of royalties, rentals or shut-in payments, etc.
(3) The responsibility for making required production and pipeline
nominations with the Texas Railroad Commission, and such other
regulatory filings as may be required. The parties agree that CIG
shall continue to make the pipeline nominations and have the
right to instruct Mesa of its nominations from the wells
committed under the "B" Contract to the same extent as Mesa shall
determine the nominations it wishes to make from such wells, and
the composite nominations to the Railroad Commission for both
parties shall then be made by Mesa to reflect such instructions.
(4) The establishment of an engineering committee to discuss various
operational matters pertaining to the production, gathering and
delivery of the natural gas and constituent elements.
(5) The specific rights and obligations of Mesa and *CIG as to the
access to, and the *supervision and maintenance of, the
production and gathering facilities, including but not limited
to, employee duties and responsibilities.
(6) The coordination and reconciling*g of production and gathering
metering facilities.
(7) Notices and representatives of Mesa and CIG.
(8) Coordination of emergency responses and press releases.
(9) The allocation of capital costs to be charged to each party in
the event of major construction or the commencement of additional
development or exploratory wells, etc.
(10) The method of receiving and handling nominations and dispatching
of natural gas to be delivered to CIG, taking into account the
rights of both Mesa and CIG to receive natural gas with
representative *Btu content from the wells committed to the "B"
Contract. Mesa shall, in the good-faith exercise of its
obligations as a prudent operator, give reasonable consideration
to CIG's volumetric nominations and well scheduling requests, so
as to permit CIG to operate the Gathering System in order to
comply with its obligations to Mesa and third parties. Mesa and
CIG shall cooperate, including having monthly meetings, in order
to carry out this and other provisions of the operating
agreement.
(11) The terms of a cost-based, reasonable operating fee payable to
Mesa by CIG. The specific components of such fee shall be
negotiated, but shall be based on the pro-rata portion of the
costs incurred by Mesa in operating the wells. The parties agree
that the operating fee to be charged to CIG will be based upon
Mesa's actual costs for each producing well capable of producing
in commercial quantities, with such operating fee being charged
to CIG on a prorata basis (i.e., such fee would be
proportionately reduced to CIG s actual percentage of gas taken
each month from total field production), such operating fee to be
inclusive all of Mesa's direct and indirect administrative
charges incurred by it, exclusive of any new capital costs but
including overhead.
(12) The terms under which Mesa shall indemnify and defend CIG and its
agents from all claims arising out of the actions of Mesa under
the operating agreement and accounting procedure, and the terms
under which CIG shall indemnify and defend Mesa and its agents
from all claims arising out of the actions of CIG under the
operating agreement and accounting procedure.
(13) The responsibility for CIG's obligations to third parties under
various agreements involving the West Panhandle Field.
(14) The responsibility for Mesa to deliver to CIG, and CIG to receive
at the wellhead meter inlet, all natural gas produced from wells
committed to the "B" Contract.
(15) The method for payment of royalties, production and property
taxes, so that each party bears its share of such expenses.
ARTICLE VII.
JOINT UNDERTAKINGS.
------------------
Section 7.01. Dismissal of Litigation.
- ------------ -----------------------
Mesa and CIG will file within ten (10) business days after the
execution of this Agreement the forms of orders of dismissal with
prejudice attached hereto as Exhibits C and D. Neither CIG nor Mesa shall
argue or assert, by way of res judicata, collateral estoppel or
otherwise, any interpretation or consequence of such orders which is
broader than the scope of the Waiver and Release of Claims referred to in
Section 7.02.
Section 7.02. Waiver and Release of Claims on the
- ------------ -----------------------------------
Settlement Date.
---------------
Concurrently with the execution of this Agreement, Mesa shall execute and
deliver to CIG a Waiver and Release of Claims in the form attached hereto an
Exhibit E.
Concurrently with the execution of this Agreement, CIG shall execute
and deliver to Mesa a Waiver and Release of Claims in the form attached
hereto as Exhibit E.
ARTICLE VIII.
ADDITIONAL PROVISIONS
---------------------
Section 8.01 "B" Contract
- ------------ ------------
The rights and obligations of CIG and Mesa under the "B" Contract are
modified only to the extent expressly required by the terms of this
Agreement and the instruments attached hereto and concurrently executed.
Section 8.02 Non-Alienation of Reserves
- ------------ --------------------------
Mesa and CIG hereby affirm that it is their intent that nothing
contained in this Agreement is to be construed as a sale, transfer or
alienation of natural gas reserves prohibited by CIG's service agreements
and the orders of the FERC in Docket No. G-1326 (issued March 1, 1951, at
10 FPC 778) and Docket No. CP73-184 (issued January 7, 1974, at 51 FPC
74).
Section 8.03 Duly Constituted Authorities
- ------------ ----------------------------
This Agreement is subject to valid laws, orders, rules and regulations
of duly constituted authorities having jurisdiction in the premises.
ARTICLE IX.
MISCELLANEOUS.
-------------
Section 9.01. Notices.
- ------------ -------
Notices and other communications provided for herein shall be in
writing and shall be delivered or mailed addressed at such address as the
party to be addressed shall have provided the other party hereto for such
purposes. All notices and other communications given to either party
hereto in accordance with the provisions of this Agreement shall be
deemed to have been given when sent by registered or certified mail, if
by mail, or when actually delivered, in each case addressed to such party
in accordance with the latest unrevoked direction from such party.
Section 9.02. Further Assurances.
- ------------ ------------------
Each party hereto shall provide such further instruments, documents
and assurances as shall be necessary or desirable to carry out, subject to
the terms and conditions hereof, and shall do all things necessary or
proper to carry out the provisions of this Agreement.
Section 9.03. Enforcement.
- ------------ -----------
Each party hereto shall be entitled to enforce this Agreement by all
remedies available to it at law or otherwise, including, without limitation
and where applicable, by action for specific performance.
Section 9.04. Successors and Assigns.
- ------------ ----------------------
This Agreement shall be binding upon and inure to the benefit of and
be enforceable by the respective successors and assigns of the parties
hereto. This Agreement shall not be assignable without the consent of the
other party, which consent shall not be unreasonably withheld.
Section 9.05. Simultaneity of Actions.
- ------------ -----------------------
All actions taken or occurring on the date of execution of this
Agreement, including the execution of documents attached as Exhibits to
this Agreement, shall be deemed to have been taken or to have occurred
simultaneously on such date. No such action shall be deemed to have been
taken or to have occurred until all such actions have been taken or have
occurred.
Section 9.06. Governing Law.
- ------------ -------------
This Agreement shall be governed by and construed in accordance with
the laws of the State of Texas.
Section 9.07. Headings.
- ------------ --------
The titles of the several Articles and Sections of this Agreement are
used herein solely for convenience of reference and shall be not be
deemed to be parts hereof or to affect the construction hereof or
otherwise to be of any force or effect.
IN WITNESS WHEREOF, the parties hereto have caused these presents to
be executed by their duly authorized representatives as of the date first
written above.
MESA OPERATING LIMITED
PARTNERSHIP
By: Pickens Operating Co.,
General Partner
WITNESS: By: /s/ Paul W. Cain
---------------------------
/s/ (Undecipherable) Paul W. Cain
- ---------------------------- President
COLORADO INTEREST GAS
COMPANY
By: Pickens Operating Co.,
General Partner
WITNESS: By: /s/ Michael G. Morris
---------------------------
/s/ Barbara J. Hanna Michael G. Morris
- ------------------------- President
<PAGE>
EXHIBIT A
May 29, 1987
Mesa Operating Limited Partnership
One Mesa Square
P. 0. Box 2009
Amarillo, Texas 79189-2009
RE: Agreement Dated January 3, 1928,
as Amended ("B" Contract)
Gentlemen:
The purpose of this letter is to confirm the agreement of Colorado
Interstate Gas Company ("CIG") and Mesa Operating Limited Partnership
("Mesa") regarding the agreement dated January 3, 1928, as amended,
commonly known as the Amarillo "B" Contract.
Mesa and CIG hereby agree that effective January l, 1990, the Amarillo
"B" Contract shall be further amended as follows:
1. Mesa shall assume the position of operator of the wells committed
to the "B" Contract. The specific terms and conditions under
which Mesa will operate such wells shall be negotiated and set
forth in a definitive Operating Agreement which the parties
contemplate executing no later than September 1, 1987.
2. Notwithstanding that Mesa shall become operator on January 1,
1990, nothing in this amendment shall be construed to modify,
amend, terminate or otherwise affect the title to all facilities,
leases,reserves and other property committed to the "B" Contract.
3. The provisions of Article V of the "B" Contract, as amemded,
concerning CIG's costs of producing the gas subject to the "B"
Contract shall be superseded by the provisions of the Operating
Agreement referred to in Paragraph 1 hereof.
4. The provisions of Article VI of the "B" Contract, as amended,
concerning the gathering by CIG of the gas subject to the "B"
Contract, shall be superseded by the terms of that certain
Gathering Agreement, dated May 29, 1987, between CIG and Mesa.
5. Except to the extent expressly set forth herein, the terms and
provisions of the "B" Contract, as heretofore amended, shall
remain in full force and effect.
If the above is in accordance with your understanding of our
agreement, please so indicate by signing in the space provided below.
Yours very truly,
COLORADO INTERSTATE GAS COMPANY
By: /s/ Michael G. Morris
--------------------------
Michael G. Morris
President
Accepted and agreed to this
29th day of May, 1987
MESA OPERATING LIMITED PARTNERSHIP
By: Pickens Operating Company,
General Partner
By: /s/ Paul W. Cain
-------------------------------
Paul W. Cain
President
<PAGE>
EXHIBIT B
GATHERING AGREEMENT
THIS AGREEMENT is made and entered into this 29th day of May, 1987, by
and between Mesa Operating Limited Partnership ("Mesa") and Colorado
Interstate Gas Company ("CIG"), to be effective August 1, 1987.
WHEREAS, Mesa and CIG have been involved in various disputes
concerning the operation of and the charges made to Mesa by CIG regarding
the West Panhandle Field Gathering System (the "Gathering System"), through
which natural gas which is produced under the agreement, as amended and
supplemented, entered on January 3, 1928, between Canadian River Gas
Company, as predecessor in interest to CIG, and Amarillo Oil Company, as
predecessor in interest to Mesa (the "'B' Contract") is gathered and
delivered; and
WHEREAS, the parties have resolved their disputes and have agreed
upon the appropriate gathering fees to be charged in the past, and the
method of calculating such fees in the future for gathering and delivering
such gas through the Gathering System; and
WHEREAS, the parties have agreed upon certain procedures to be
followed in order to avoid the recurrence of certain disputes regarding the
operation of the Gathering System in the future;
NOW, THEREFORE, Mesa and CIG, in consideration of mutual promises,
covenants, releases and agreements contained herein, do agree as follows:
I.
For all natural gas delivered& through the Gathering System to Mesa or
its predecessor, Amarillo Oil Company, under the "B" Contract for the
period commencing October 1, 1984, through the Settlement Data as
determined pursuant to the Agreement of Compromise and Settlement between
the parties: (the "Settlement Date"), the amounts which Mesa or its
predecessor, Amarillo Oil Company, has paid to crG shall be considered to
be full and complete compennatiom for such gathering services. No further
amounts shall be payable by Mesa, nor shall any refunds be owed by CIG, for
such gathering services during such period, except for volumes delivered
prior to the Settlement Date for which payment has not been made by that
date. Mesa and CIG agree that Mesa shall pay CIC, as full and-complete
compensation for such volumes delivered, at the same rate per Mcf that Mesa
has been paying for deliveries during prior months in 1987, without-regard
to amounts invoiced by CIG.
II.
CIG shall deliver to Mesa at the inlet to the Fain Processing Plant or
such alternate delivery point as Mesa shall request (subject to CIC's right
to reject such request, in whole or in part, in the reasonable exercise of
its discretion giving due consideration to the interests of both parties),
the natural gas Mesa is entitled to receive under the "B" Contract. For 411
such deliveries to Mesa for the period from the Settlement Date through
December 31, 1989 the gathering fee payable by Mesa to CIG shall be 44
cents per Mcf.
III.
For all natural gas produced under the "B" Contract and delivered
through the Gathering System to Mesa on and after January 1, 1990, CIG
shall calculate gathering fee which will be based upon its annual costs,
which shall be the sum of (a) its direct out-of-pocket expenses (including
all taxes not related to income taxes) reasonably incurred in operating the
Gathering System; (b) 20% of such actual, direct out-of-pocket expenses to
compensate CIG for general and administrative expenses; (c)depreciation on
the riginal cost of the Gathering System at the applicable depreciation
rate for gathering, facilities owned by CIG, as approved in a final order
of the Regulatory Commission (the "FERC"), with such depreciation not to
accumulate beyond the gross plant cost; and (d) a return (including cost
less accumulated depreciation for the Gathering System) at the applicable
overall rate of return provided to CIG in a final order of the FERC. Items
(c) and (d) will be adjusted retroactively, as appropriate, to reflect the
effect of any final order of the FERC. Mesa shall provide its prorata
share of fuel actually used at its own cost (including any necessary
facilities) for the gathering of all gas delivered to Mesa, and such fuel
is provided by Mesa shall not be included in CIG's calculations of cost in
operating the Gathering System. Mesa and CIG shall pursue with diligence
the obtaining of any necessary regulatory approvals to carry out the terms
of this Article III. CIG shall calculate and Mesa shall pay to CIG each
month a gathering fee for the volumes gathered for Mesa and redelivered
from the Gathering System during that month. Such gathering fee shall be
estimated for each Mcf so delivered on the basis of the prior year's actual
costs, as set forth above, divided by the total volumes of gas gathered and
redelivered through the Gathering System for the prior year. Such estimate
shall take into account any significant known and measurable changes
expected to occur during the next billing year, if so agreed to by both
parties. The estimated billing basis will be furnished to Mesa on or before
November 30th of the prior year. On or before the April 30th succeeding
each billing year, CIG shall account to Mesa for actual costs and volumes,
with any necessary payment by one party to the other party due 30 days
after such accounting is received by Mesa.
IV.
In the event that the FERC shall allocate or assign costs, by a final
order in any proceeding involving rates charged by CIG, to deliveries of
natural gas to Mesa through the Gathering System, or otherwise treat the
gathering fee payable by Mesa, as if the gathering fee were greater than
the amount otherwise payable by Mesa to CIG, Mesa shall increase as of the
effective date of the FERC action the fee payable to CIG by an amount equal
to 50 percent of the increase, as allocated to Mesa in the determination of
CIG's rates. In the event that such final order of the FERC shall have the
effect of treating the gathering fee as if it were greater than 20 cents
per Mcf more than the gathering fee otherwise payable by Mesa to CIG under
this Agreement, then Mesa, upon request by CIG, agrees to moot with CIG and
enter into good-faith negotiations to determine what new arrangements, if
any, are equitable and reasonable under the circumstances in existence.
V.
CIG shall operate the Gathering System in a fair operator and without
undue discrimination so an to reasonably assure that Mesa receives in the
natural gas and drip liquids, if any, delivered to Mesa an average Btu
content ("Delivered Btu") representative of the average Btu content found
in the natural gas produced from all wellecommitted under the "B" Contract
("B Contract Btu"). In the event that the Delivered Btu during any fiscal
year exceeds two percent (2%) greater or less than the B Contract Btu
during that fiscal year, CIG shall correct the imbalance in the Delivered
Btu to the extent such imbalance exceeds two percent greater or less than
the B Contract Btu by delivering natural gas containing a higher or lower
average Btu content than that contained in the B Contract Btu during the
next fiscal year and thereafter until such time as the imbalance has been
reduced to within such two percent of the average. To the extent any
additional facilities are reasonably necessary to correct such imbalance,
Mesa shall have the option to request the installation of such facilities,
provided that Mesa agrees to reimburse CIG for all costs reasonably
incurred in constructing and installing same. If Mesa chooses not to
request installation of such facilities, CIG's obligation to Mesa, if any,
to deliver natural gas containing Delivered Btu within two percent (2%) of
the "B" Contract Btu shall be suspended to the extent such additional
facilities are necessary.
V.
CIG acknowledges that Mesa is involved in a pending lawsuit, (Mapco
Westpan, Inc. v. Pioneer Corp., Case No. 62,922-A, 47th Judicial District
Court, Potter County, Texas). CIC agrees, based upon Mesa's claims of
ownership liquids asserted in such lawsuit, to collect such drips over
which it has control, on a monthly basis, and to use reasonable efforts for
the marketing of such drips to achieve the highest net value. As soon as
reasonably possible, CIG agrees to file with the District Court of Potter
County, Texas, an appropriate interpleader action wherein CIC shall tender
on a continuing basis the not revenues attributable to the sale of such
drips, into the registry of such Court; and petition such Court to
ascertain the lawful owner of such drips and the revenues attributable
thereto. In consideration of CIC's filing the interpleader suit as required
herein, Mesa hereby agrees to defend, indemnify, and hold CIG harmless from
and against any and all claims, damages, losses, causes of actions,
judgments or other actions, including costs of suit and attorneys fees, if
any, which may arise directly from the interpleader suit to be filed by
CIG, and which may be brought about, through and by virtue of, claims
and/or demands which Mapco Westpan, Inc., its predecessors and successors
in interest allege to have suffered as a result of the denial to it of the
possession of the drips as aforesaid. Upon the conclusion of such
interpleader action, CIG and Mesa shall enter into a new arrangement, if
applicable, consistent with the court's judgment.
VII.
CIG and Mesa shall keep records sufficient to document requests or
nominations by Mesa for gas deliveries from CIG, and deliveries by CIC to
Mesa. Each party shall have the right at all reasonable times to examine
the books, records and charts of the other party to the extent necessary to
verify the accuracy of any request or nomination, statement, payment
calculation or determination made pursuant to the provisions of this
Agreement. If any error shall be discovered, proper adjustment and
correction thereof shall be made and any refunds due shall be made as
promptly as practicable thereof tor.
IN WITNESS WHEREOF, the parties hereto have caused these presents to be
executed by their duly authorized representatives as of the date first
written above.
MESA OPERATING LIMITED PARTNERSHIP
By: Pickens Operating Co.,
General Partner
By: /s/ Paul W. Cain
------------------------
Paul W. Cain
President
COLORADO INTERSTATE GAS COMPANY
By: /s/ Michael Morris
----------------------------
Michael Morris
President
<PAGE>
EXHIBIT C
IN THE UNITED STATES DISTRICT COURT
FOR THE NORTHERN DISTRICT OF TEXAS
AMARILLO DIVISION
MESA OPERATING LIMITED S
PARTNERSHIP, S
Plaintiff, S
VS. S Civil Action No.
S 2-86-0300
COLORADO INTERSTATE GAS S
COMPANY, S
S
Defendant. S
ORDER DISMISSING CLAIMS WITH PREJUDICE
--------------------------------------
On the _____ day of _______________ 1987, came on for consideration a
stipulation of dismissal with prejudice filed by all parties to this suit.
The Court is of the opinion that the stipulation is in order and should be
granted. It is therefore:
ORDERED that all claims of Mesa Operating Limited Partnership against
Colorado Interstate Gas Company in this suit are dismissed with prejudice;
and it is further,
ORDERED that all claims filed by Colorado Interstate Gas Company
against Mesa Operating Limited Partnership in this suit are dismissed with
prejudice.
________________________________
Judge Presiding
<PAGE>
EXHIBIT D
DISTRICT COURT, COUNTY OF EL PASO, STATE OF COLORADO
Civil Action No. 86CV5573, Division 9
_________________________________________________________________________
ORDER OF DISMISSAL
_________________________________________________________________________
COLORADO INTERSTATE GAS COMPANY,
Plaintiff,
V.
MESA OPERATING LIMITED PARTNERSHIP,
Defendant.
_________________________________________________________________________
Came on for consideration the stipulation for dismissal of Plaintiff
Colorado Interstate Gas Company (CIG) and Defendant Mesa Operating Limited
Partnership (Mesa) in the above-captioned action. The Court is of the
opinion that the stipulation is in order and should be granted. It is
therefore:
ORDERED that all claims by Plaintiff CIG against Mesa in this suit
be dismissed with prejudice; save and except those claims relating to
Mesa's alleged breach of the Celeron Agreement, which is dismissed without
prejudice; it is further
ORDERED that all claims by Mesa against CIG in this suit be dismissed
with prejudice.
DATED this _____ day of _______________, 1987.
______________________________________
Judge Presiding
<PAGE>
EXHIBIT E
WAIVER AND RELEASE OF CLAIMS BY
MESA OPERATING LIMITED PARTNERSHIP
KNOW ALL MEN BY THESE PRESENTS THAT:
WHEREAS, Mesa Operating Limited Partnership (hereinafter referred to
as "Mesa"), a limited partnership organized under the laws of the State of
Delaware with its principal place of business in Amarillo, Texas has
compromised certain claims against Colorado Interstate Gas Company
(hereinafter referred to as "CIG"), a corporation organized under the laws
of the State of Delaware with its principal place of business in Colorado
Springs, Colorado; and
WHEREAS, in connection with such compromise, Mesa has agreed to
execute and deliver a waiver and release of certain claims, and this waiver
and release of claims is being executed and delivered pursuant to such
agreement; and
WHEREAS, for the purposes hereof the term "Claim" shall mean any
right, remedy, claim or other action or assessment for money or other
property (as damages, either direct or indirect, or otherwise) and for
breach of contract, for rescission, for termination, for specific
performance or for other equitable relief, and whether arising under an
agreement, as amended and supplemented, initially entered on January 3,
1928, between Amarillo Oil Company (hereinafter referred to as "AOC"), as
predecessor to Mesa, and Canadian River Gas Company, as predecessor to
CIG, (hereinafter, as the same has been or may hereafter be amended,
modified or supplemented, referred to as the "B" Contract) or at common
law or in equity or created by any rule of law, regulatory order, rule or
regulation, statute, constitution or otherwise, and whether now known or
unknown, discovered or undiscovered, disclosed or undisclosed, fixed or
contingent, and whether or not asserted or unasserted, in any litigation,
including but not limited to, the Amarillo Litigation or the Colorado
Springs Litigation, by or on behalf of Mesa or any subsidiary, parent,
partner or affiliate thereof or any direct or indirect customer of any
thereof against CIG or Canadian River Gas Company, its predecessor in
interest, or any subsidiary or affiliate, or any director, officer,
employee, partner, agent or stock holder, pant, present, or future, of any
thereof which constitutes, is tantamount to, relates to, arises out of or
is based upon:
(a) overcharges by CIG for any quantity of natural gas
delivered by CIG to Mesa under the "B" Contract at any
time or times prior to the Settlement Date whether such
charges shall relate to compensation for production,
compression, gathering, delivery, or any other aspect of
the provision of volumes of natural gas to Mesa or AOC
under the "B" Contract;
(b) the failure of CIG to deliver the volumes of gas
required to be delivered by CIG to Mesa or AOC under the
"B" Contract at any time or times prior to the
Settlement Date; or
(c) the failure of CIG to deliver to Mesa or AOC natural gas
containing field wide average Btu content at any time or
times prior to the Settlement Date;
(d) the failure to account to Mesa or AOC for the proceeds of
gas condensate liquids ("drips") collected from the "B"
Contract gas at any time or times prior to the Settlement
Date; or
(e) any other Claim for alleged breach of, or failure to
comply in any respect with, the "B" Contract, at any time
or times prior to the Settlement Date; and
WHEREAS, for the purposes hereof, the term "Amarillo Litigation" shall
mean that lawsuit instituted by Mesa against CIG, and all causes of action
asserted therein, whether as a claim or counterclaim, in the District
Court of Potter County, Texas, 251st Judicial District, Cause No. 68
002C, and subsequently removed to the United States District Court for the
Northern District of Texas, Civil Action No. 2-86-0300; and
WHEREAS, for the purposes hereof, the term "Colorado Springs
Litigation" shall mean that lawsuit instituted by CIG against Mesa, and
all causes of action asserted therein, whether as a claim or counterclaim,
in the District Court of El Paso County, Colorado, Civil Action No. 86 CV
5573; and
WHEREAS, for the purposes hereof, the term "Settlement Date" shall
mean the date upon which the Agreement of Compromise and Settlement between
Mesa and CIG shall become effective, which shall be August 1, 1987, or
such other business day in the State of Texas selected by mutual agreement
in writing of Mesa and CIG;
NOW, THEREFORE, in consideration of the aforesaid compromise and other
good and valuable consideration, the receipt and sufficiency whereof are
hereby acknowledged, Mesa does fully, finally and forever release CIG
Canadian River Gas Company, and the subsidiaries, affiliates directors,
officers, employees, partners, agents and stock holders, in each case past,
present, and future, of each thereof from all Claims which Claims Mesa
agrees shall, from and after the Settlement Date, be fully and finally
released and forever waived regardless of the occurrence or nonoccurrence
of any event or events after the Settlement Date, and, further Mesa
undertakes, covenants and agrees that, from and after the Settlement Date,
it shall never litigate or relitigate or cause or permit any person acting
for it or in its behalf to litigate or relitigate, directly or indirectly,
collaterally or otherwise, any Claim or other issue resolved by the said
compromise, and Mesa undertakes that it has not and will not assign any
Claims in whole or in part.
To the extent that litigation is instituted against Mesa by any party
other than CIG with respect to Claims otherwise released hereunder, this
Waiver and Release shall be null and void and of no further effect to the
extent of such third-party litigation, and Mesa may assert in defense of
such third-party litigation any cross claim or third-party claim against
CIG as if this Waiver and Release had never been entered into.
IN WITNESS WHEREOF, Mesa has caused these presents to be executed by
its duly authorized representative this 29th day of May, 1987, in the
presence of the undersigned competent witness.
MESA OPERATING LIMITED PARTNERSHIP
By: Pickens Operating Co.,
General Partner
By: /s/ Paul W. Cain
------------------------------
Paul W. Cain
President
WITNESS:
/s/ Stephen A. Wakefield
- ---------------------------------
<PAGE>
ACKNOWLEDGEMENT
STATE OF TEXAS
-----
COUNTY OF HARRIS
------
On this the 29th day of May, 1987, before me appeared
Paul W. Cain to me personally known, who, being by me
- ------------
duly sworn did say that he is the President of Mesa Operating
---------
Limited Partnership, and that the seal affixed to said instrument is the
official seal of said partnership and that the instrument was signed and
sealed in behalf of the partnership by authority of its Management
Committee and that he acknowledged the instrument to be the free act
--
and deed of the partnership.
/s/ Cindy Cavness
-----------------------------------
NOTARY PUBLIC, IN AND FOR THE STATE
OF TEXAS
-----
CINDY CAVNESS
-----------------------------------
PRINTED NAME OF NOTARY PUBLIC
My Commission Expires:
03-12-90
-----------------------------------
<PAGE>
EXHIBIT F
WAIVER AND RELEASE OF CLAIMS BY
COLORADO INTERSTATE GAS COMPANY
KNOW ALL MEN BY THESE PRESENTS THAT:
WHEREAS, Colorado Interstate Gas Company (hereinafter referred to as
"CIG"), a corporation organized under the laws of the State of Delaware
with its principal place of business in Colorado Springs, Colorado, has
compromised certain claims against Mesa Operating Limited Partnership
(hereinafter referred to as "Mesa"), a limited partnership organized under
the laws of the State of Delaware with its principal place of business in
Amarillo, Texas; and
WHEREAS, in connection with such compromise, CIG has agreed to execute
and deliver a waiver and release of certain claims, and this waiver and
release of claims is being executed and delivered pursuant to such
agreement; and
WHEREAS, for the purposes hereof the term "Claim" shall mean any
right, remedy, claim or other action or assessment for money or other
property (as damages, either direct or indirect, or otherwise) and for
breach of contract, for rescission, for termination, for specific
performance or for other equitable relief, and whether arising under an
agreement, as amended and supplemented, initially entered on January 3,
1928, between Canadian River Gas Company, as predecessor to CIG, and
Amarillo Oil Company (hereinafter referred to as "AOC"), as predecessor to
Mesa, (hereinafter, as the same has been or may hereafter be amended,
modified or supplemented, referred to as the "'B' Contract") or at common
law or in equity or created by any rule of law, regulatory order, rule or
regulation, statute, constitution or otherwise, and whether now known or
unknown, discovered or undiscovered, disclosed or undisclosed, fixed or
contingent, and whether or not asserted or unassorted, in any litigation,
including but not limited to the Amarillo Litigation or the Colorado
Springs Litigation, by or on behalf of CIG or any subsidiary, parent or a
affiliate thereof or any direct or indirect customer of CIG against Mesa or
AOC, or any subsidiary or affiliate, or any director, officer, employee,
partner, agent, or stock holder, past, present, or future, of any thereof
which constitutes, is tantamount to, relates to, arises out of or is based
upon:
(a) the failure, whether actual or anticipated, of Mesa or AOC
to fully and adequately compensate CIG for any quantity of
natural gas delivered by CIG to Mesa or AOC under the "B"
Contract at any time or times prior to the Settlement Date
whether such charges shall relate to compensation for
production, compression, gathering, delivery, or any other
aspect of the provision of volumes of natural gas to Mesa or
AOC under the "B" Contract, except for volumes delivered
prior to the Settlement Date for which payment has not been
made by that date;
(b) the failure of Mesa or AOC to negotiate in good faith a new
gathering fee for quantities of gas delivered by CIG to Mesa
or AOC under the "B" Contract at any time or times prior to
the Settlement Date;
(c) the extraction and sale or use by Mesa or AOC of ethane,
propane, and heavier hydrocarbons from the stream of gas
delivered by CIG to Mesa or AOC at any time or times prior
to the Settlement Date;
(d) the operation of the New Fain Gas Processing Plant by Mesa
or AOC to extract hydrocarbons from the gas stream in a
manner alleged to cause CIG to deliver volumes of natural
gas which would otherwise be greater than that amount
required to serve the City of Amarillo and its environs at
any time or times prior to the Settlement Date; or
(e) any other claim for alleged breach of, or failure to comply
in any respect with, the "B" Contract, at any time or times
prior to the Settlement Date; and
WHEREAS, for the purposes hereof, the term "Amarillo Litigation" shall
mean that lawsuit instituted by Mesa against CIG, and all causes of action
asserted therein, whether as a claim or counterclaim, in the District Court
of Potter County, Texas, 251st Judicial District, Cause No. 68 002C, and
subsequently removed to the United States District Court for the Northern
District of Texas, Civil Action No. 2-86-0300; and
WHEREAS, for the purposes hereof, the term "Colorado Springs
Litigation" shall mean that lawsuit instituted by CIG against Mesa, and all
causes of action asserted therein, whether as a claim or counterclaim, in
the District Court of El Paso County, Colorado, Civil Action No. 86 CV
5573; and
WHEREAS, for the purposes hereof, the term "Settlement Date" shall
mean the date upon which the Agreement of Compromise and Settlement between
Mesa and CIG shall become effective, which shall be August 1, 1987, or such
other business day in the State of Texas selected by mutual agreement in
writing by Mesa and CIG;
NOW, THEREFORE, in consideration of the aforesaid compromise and other
good and valuable consideration, the receipt and sufficiency whereof are
hereby acknowledged, CIG does fully, finally and forever release Mesa, AOC,
and the subsidiaries, affiliates, directors, officers, employees, partners,
agents, and stock holders, in each case past, present, and future, of each
thereof from all Claims which Claims CIG agrees shall, from and after the
Settlement Date, be fully and finally released and forever waived
regardless of the occurrence or nonoccurrence of any event or events after
the Settlement Date, and, further CIG undertakes, covenants and agrees
that, from and after the Settlement Date, it shall never litigate or
relitigate or cause or permit any person acting for it or in its behalf to
litigate or relitigate, directly or indirectly, collaterally or otherwise,
any claim or other issue resolved by the said compromise, and CIG
undertakes that it has not and will not assign any Claims, in whole or in
part.
To the extent that litigation is instituted against CIG by any party
other than Mesa with respect to Claims otherwise released hereunder, this
Waiver and Release shall be null and void and of no further effect to the
extent of such third-party litigation, and CIG may assert in defense of
such third-party litigation any cross claim or third-party claim against
Mesa as if this Waiver and Release had never been entered into.
IN WITNESS WHEREOF, CIG has caused these presents to be executed by
its duly authorized representative this 29th day of May, 1987, in the
presence of the undersigned competent witness.
COLORADO INTERSTATE GAS COMPANY
WITNESSES: By: /s/ Michael G. Morris
-------------------------------
Michael G. Morris
President
/s/ Barbara J. Hanna
- --------------------------------
<PAGE>
EXHIBIT F
ACKNOWLEDGEMENT
STATE OF MICHIGAN
--------
COUNTY OF WAYNE
-----
On this the 29th day of May, 1987, before me appeared
Michael G. Morris to me personally known, who, being by me
- -----------------
duly sworn did say that he is the President of Colorado
---------
Interstate Gas Company, and that the seal affixed to said instrument is the
official seal of said corporation and that the instrument was signed and
sealed in behalf of the corporation by authority of its Board of Directors
and that he acknowledged the instrument to be the free act
--
and deed of the corporation.
/s/ Judy M. Finnern
----------------------------------
NOTARY PUBLIC, IN AND FOR THE STATE
OF MICHIGAN
--------
JUDY M. FINNERN
----------------------------------
PRINTED NAME OF NOTARY PUBLIC
My Commission Expires:
JUDY M. FINNERN
----------------------------------
Notary Public, Macomb County, Michigan
Acting in Wayne County
My Commission Expires June 28, 1989
<PAGE>
AMENDMENT TO GATHERING AGREEMENT
This Amendment to Gathering Agreement is made and entered into as of
this 15th day of July, 1990, by and between Mesa Operating Limited
Partnership ("Mesa") and Colorado Interstate Gas Company ("CIG").
WHEREAS, Mesa and CIG entered into that certain Gathering Agreement
dated May 29, 1987 (but effective August 1, 1987) covering certain
deliveries by CIG to Mesa from the West Panhandle Field;
WHEREAS, a disagreement has arisen between the parties as to the
specific conditions under which Mesa is to provide its pro rata share of
fuel gas in kind as described in the Gathering Agreement;
WHEREAS, Mesa and CIG wish to resolve such dispute and to provide for
an option for Mesa to purchase fuel gas or to supply fuel gas in kind in
conjunction with the execution of other related documents of even date.
NOW, THEREFORE, Mesa and CIG, in consideration of the mutual promises
contained herein and other good and valuable consideration, do hereby agree
that effective as of July 15, 1990:
1. The third sentence of Article III of the Gathering Agreement is
deleted:
2. The following new Article IV shall be added to the Gathering
Agreement:
Subject to the provisions of this Article IV, Mesa shall
have the option of providing its pro rata share of fuel in
kind (in MMBtus) at its own cost (including any necessary
facilities) for the gathering of all gas delivered to Mesa or
separately pay CIG, at its WACOG, for Mesa's pro rata share
of fuel actually used. "CIG's WACOG" means CIG's projected
weighted average cost of gas from all field sources, as shown
in CIG's Quarterly Purchased Gas Adjustment (PGA) filing with
the FERC. In the event CIG no longer files a quarterly PGA,
CIG and Mesa shall negotiate a substitute measure of CIG's
WACOG. If Mesa elects to provide such fuel in-kind, then such
fuel reimbursement volumes shall be delivered to CIG from the
wells or other delivery points listed on Exhibit "A" hereto
which is made a part of this Agreement.
Prior to November 30, 1990, and each November 30 thereafter,
CIG and Mesa shall agree upon an estimate of Mesa's pro rata
share of fuel gas to be used in calendar year 1991, and each
calender year thereafter. In agreeing to such an estimate, the
parties shall consider Mesa's pro rata share of fuel actually
used during the most recent 12-month period for which such data
is available, any underage or overage in fuel reimbursement
volumes identified to date, Mesa's expected take requirements
under the "B" Contract, historic field compressor fuel usage,
and other relevant factors. Prior to November 30, 1990, and
each November 30 thereafter, CIG shall also provide Mesa, as
part of the estimated billing basis described in Article III
hereof, an estimate of the cost of fuel, based on CIG's WACOG,
if purchased by Mesa from CIG in accordance with the provisions
of this Article IV.
Prior to January 1, 1991, and each January 1 thereafter,
Mesa shall notify CIG in writing of its election to provide a
designated percentage of its pro rata share of fuel in kind
and pay for any remaining share for the upcoming calendar year
at a price equal to CIG's WACOG. If Mesa elects to provide
all or part of its pro rata share of fuel in kind, Mesa's share
for a calendar year shall be delivered to CIG any time during
the period April through October (Summer Period) commencing with
the calendar year 1991; provided, however, Mesa shall have the
right to deliver to CIG at a daily rate of flow, of 1/120th of
the estimated annual fuel usage volume each day of the Summer
Period until a volume equal to the estimated annual fuel use
volume has been delivered. For any month of a Summer Period in
which Mesa elects to deliver fuel in kind, Mesa shall provide
monthly and daily volume nominations consistent with Article VI
of the Storage Service Agreement between CIG and Mesa dated July 15,
1990. CIG shall have the right to curtail such deliveries for up
to a total of 60 days during any Summer Period.
If during a particular calendar year, the estimate of Mesa's
pro rata share of fuel gas to be used during such calendar year is
either more or less than Mesa's pro rata share of fuel gas actually
used; then the estimate for the immediately succeeding calendar year
shall be either decreased or increased by the amount of such excess
or deficient estimate. Further, if during a particular calendar
year, the volume of fuel gas which Mesa delivered in kind to CIG
plus the volume of fuel gas which Mesa purchased from CIG, all as
provided for herein, was either more or less than Mesa's pro rata
share of fuel gas actually used during such calendar year, then the
estimate of the volume of fuel gas which Mesa would otherwise be
obligated to deliver in kind or purchase from CIG during the
immediately succeeding calendar year shall be reduced or increased
by the amount of such excess or deficient volume.
In lieu of providing the designated percentage of its pro rata
share of fuel in kind for a calendar year, Mesa may elect to pay for
its share at CIG's WACOG.
For gas so purchased from CIG, CIG will invoice Mesa and Mesa
will pay CIG monthly (as part of the gathering fee described in
Article III) based on CIG's estimate of Mesa's pro rata share of
fuel used during the year. On or before April 30, 1991, and each
April 30 thereafter, CIG shall account to Mesa (as part of the
accounting described in Article III above) for Mesa's share of
fuel actually used in the prior calendar year (if Mesa paid CIG
for fuel in the prior year).
CIG and Mesa agree that CIG will provide Mesa with a minimum
of 100 psig delivery pressure at the outlet of CIG's meter station
at Field Station 20 on as consistent a basis as is practicable in
light of the prudent operation of the Gathering System. If CIG's
failure to do so is the cause for Mesa being unable to take its
allowed Maximum Daily Volumes pursuant to Section 2.4(a) of the
Supplemental Stipulation and Agreement dated July 15, 1990, Mesa
shall have the right to make up such deficient volume at any time
by having the option of taking up to 5 Mmcfd in excess of its then
current Maximum Daily Volume (as set forth in the aforementioned
Supplemental Stipulation and Agreement) until the deficiency is
made up. Mesa's right to make up such deficient volumes shall be
subject to: (1) Mesa's providing notice to CIG not less than 24
hours in advance of the gas day upon which Mesa plans to take such
make-up volumes in excess of its Maximum Daily Volume set forth in
the Supplemental Stipulation and Agreement; and (2) Mesa shall have
no right to any such make up volumes on any Peak Day as described
in Section 2.5(b) of the Supplemental Stipulation and Agreement.
Such right of make-up shall be Mesa's sole remedy in the event CIG
is unable to provide the 100 psig delivery pressure, except that in
the event Mesa is unable to make up any deficiency within the
following six months because of CIG's failure to maintain the above-
described 100 psig delivery pressure so that Mesa can take the make-
up volumes plus other volumes to which Mesa is entitled, Mesa may
pursue in addition any other remedy or remedies that it may have.
CIG and Mesa further agree that the facility and operating costs
associated with any new facilities required to meet such pressure
shall be treated in accordance with this Agreement.
3. The existing Articles designated successively as "IV," "V,"
"V"{sic}, and "VII" shall be renumbered Articles "V,", "VI," "VII" and
"VIII" respectively.
4. This Amendment to Gathering Agreement shall continue in full force
and effect from July 15, 1990, until (i) the Supplemental Stipulation and
Agreement dated July 15, 1990, is terminated in accordance with Section
4.1(a) thereof or (ii) an event described in Section 5.2 thereof occurs.
Upon termination of the Supplemental Stipulation and Agreement, the terms
and provisions of the Gathering Agreement shall remain as if this Amendment
to Gathering Agreement was never entered into.
5. As amended herein and subject to the provisions of Paragraph 4
above, the Gathering Agreement shall remain in full force and effect.
IN WITNESS WHEREOF, CIG and Mesa cause this Amendment to Gathering
Agreement to be executed by the duly authorized representatives to be
effective as of the date first written above.
COLORADO INTERSTATE GAS COMPANY
By: /S/ C. S. Hobbs
----------------------------
C. S. Hobbs
Senior Vice President
MESA OPERATING LIMITED PARTNERSHIP,
a Limited Partnership,
By: PICKENS OPERATING COMPANY.
General Partner
By: /S/ Claude Jenkins
------------------------------
Claude Jenkins
Vice President Marketing
<PAGE>
July 10, 1990
FEDERAL EXPRESSED
- -----------------
Donald E. Williams, Esquire John E. Archibold, Esquire
John P. Roddy, Esquire Staff Counsel
Staff Counsel Colorado Public Utilities Commission
Federal Regulatory Commission 1580 Logan Street
825 North Capitol Street, N.E. Denver CO 80202
Washington DC 20426
Stephen H. Kaplan, Esquire
Mr. Jon R. Whitney Office of City Attorney
Executive Vice President and City and County of Denver
Chief Operating Officer City and County Building - Room 353
Colorado Interstate Gas Company Denver Co 80202
2 North Nevada
Colorado Springs CO 80944
Gregory L. Johnson, Esquire
City of Colorado Springs
James K. Tarpey, Esquire 104 South Cascade Avenue - Suite 204
Counsel for Colorado Springs CO 80903
Public Service Company of Colorado
Western Slope Gas Company and James K. McElligott, Esquire
Cheyenne Light, Fuel & Power Company Natural Gas Pipeline Company of
Kelly, Stansfield & O'Donnell America
550 Fifteenth Street - Suite 900 701 East 22nd Street
Denver CO 80202 Lombard IL 60140
Gentlemen:
Subject: Uncontested Settlement Agreements on
Reserved Issues; In the Matter of
Colorado Interstate Gas Company,
FERC Docket No. RP79-59
On December 31, 1980, the Federal Energy Regulatory Commission Staff,
Amarillo Oil Company {predecessor-in-interest to Mesa Operating Limited
Partnership ("Mesa")}, Colorado Interstate Gas Company ("CIG") and the
other parties to whom this letter is addressed entered into the Uncontested
Settlement Agreement on Reserved Issues relating to certain matters arising
connection with deliveries of gas from CIG to Amarillo Oil Company from the
West Panhandle Field pursuant to the "B" Contract dated January 3, 1928, as
described more fully in the proceedings in which the Uncontested Settlement
was filed, Colorado Interstate Gas Company, FERC Docket No. RP79-59. The
Uncontested Settlement was accepted and approved by FERC order dated March
4, 1981. 14 F.E.R.C. para. 61,216.
Many fundamental changes have taken place in the natural gas industry
and in the marketplace since the Uncontested Settlement was entered into in
1980. The Uncontested Settlement was devised in the midst of an acute
natural gas shortage, whereas at present there is adequate gas
deliverability. In contrast, the volumetric limits on "B" Contract
deliveries to Mesa are unchanged from the original provisions that were
negotiated under conditions of severe shortage. Moreover, gas is available
at prices now that generally lower than the prices of available supplies in
1980. However, because of its automatic escalation provisions, the
Uncontested Settlement requires substantially larger surcharge payments now
than in the years when it first went into effect.
For these reasons and others, Mesa believes that the provisions of the
Uncontested Settlement are inappropriate in the light of current conditions
and unfair to Mesa. The Uncontested Settlement, in Paragraph 3.1, reserves
to Mesa, as well as to other parties, the right to withdraw from the
Uncontested Settlement and thereby terminate it. Because of the wide
disparity between the terms of the Uncontested Settlement and current
conditions, Mesa has determined that it must exercise this right. However,
before doing so, Mesa entered into discussions with CIG to explore the
possibility of reaching a new settlement to replace the Uncontested
Settlement. These negotiations have resulted in an agreement between Mesa
and CIG to a proposed new settlement that Mesa believes is fair to CIG and
its customers, as well as to Mesa.
In accordance with its agreement with CIG, Mesa is withdrawing from
the Uncontested Settlement effective July 15, 1990, and pursuant to
Paragraph 3.1 of the Uncontested Settlement, Mesa hereby gives notice of
such withdrawals. A copy of Mesa's notice to the Commission is enclosed
with this letter.
If approved by the FERC, the new proposed settlement is to take effect
on July 15, 1990. Pending Commission consideration and approval of the
proposed settlement, Mesa has agreed to abide by the volumetric limits in
the proposed settlement and to pay into escrow the amounts required under
it.
The proposed settlement documents will be furnished to you as soon as
possible. Mesa, as well as CIG, will be ready to answer any questions or
discuss any comments that you may have.
Sincerely,
MESA OPERATING LIMITED PARTNERSHIP
By Pickens Operating Co.,
General Partner
By /s/ Paul C. Cain
------------------------------
Paul C. Cain, President and
Chief Operating Officer
nr
Enclosure
<PAGE>
July 10, 1990
Lois D. Cashell, Secretary
Federal Energy Regulator Commission
825 North Capitol Street, N.E.
Washington DC 20426
Dear Ms. Cashell:
Subject: Uncontested Settlement Agreement on
Reserved Issues; In the Matter of
Colorado Interstate Gas Company,
FERC Docket No. RP79-59
Reference is made to the Uncontested Settlement Agreement on Reserved
Issues (the "Uncontested Settlement") dated December 31, 1980, entered into
among Federal Energy Regulatory Commission Staff, Colorado Interstate Gas
Company ("CIG"), Amarillo Oil Company {predecessor-in-interest to Mesa
Operating Limited Partnership ("Mesa"}], Public Service Company of
Colorado, the Colorado Public Utilities Commission, Western Slope Gas
Company, Cheyenne Light, Fuel & Power Company, the City and County of
Denver, the City of Colorado Springs and Natural Gas Pipeline Company of
America. The Uncontested Settlement was accepted and approved by order
dated March 4, 1981, in Colorado Interstate Gas Company, FERC Docket No.
RP79-59, 14 F.E.R.C. para. 61,216.
Pursuant to Paragraph 3.1 of the Uncontested Settlement, Mesa as
successor-in-interest to Amarillo Oil Company hereby gives notice of
withdrawal from the Uncontested Settlement effective July 15, 1990.
Sincerely,
MESA OPERATING LIMITED PARTNERSHIP
By Pickens Operating Co.,
General Partner
By /S/ Paul C. Cain
------------------------------
Paul C. Cain, President and
Chief Operating Officer
nr
Copy to FERC Staff Counsel
All Parties to the Uncontested Settlement
Agreement on Reserved Issues
<PAGE>
<TABLE>
EXHIBIT "A"
TO THAT AMENDMENT TO GATHERING AGREEMENT
between
COLORADO INTERSTATE GAS COMPANY (Buyer)
and
MESA OPERATING LIMITED PARTNERSHIP
Acting on Behalf of Itself and as Agent for
MESA MIDCONTINENT LIMITED PARTNERSHIP (Seller)
DATED: July 15, 1990
SOURCE OF GAS AND DELIVERY POINT(S).
<CAPTION>
Delivery Point/ Meter Working Percent of
Well Name Location No. Interest Ownership
- ---------------- ------------ ------- --------- ----------
<S> <C> <C> <C> <C>
Akers, Barnery 1 05-26S-39W 001630 100.00 100.00
Hamilton, KS
Akers, Barnery 2-5 05-26S-39W 001631 100.00 100.00
Hamilton, KS
Brothers, I.S. 1 09-26S-39W 020620 100.00 100.00
Hamilton, KS
Brothers 2A 03-26S-39W 020690 100.00 100.00
Hamilton, KS
Brothers 3-3 03-26S-39W 020600 100.00 100.00
Hamilton, KS
Brothers 4-9 09-26S-39W 020700 100.00 100.00
Hamilton, KS
Brothers 5-9 09-26S-39W 020710 100.00 100.00
Hamilton, KS
Fed Farm Mortgage 1-10 10-26S-39W 033758 100.00 100.00
Hamilton, KS
Fields, R. S. 1-36 36-25S-39W 035100 100.00 100.00
Hamilton, KS
Frease, E. M. 1 20-26S-39W 036420 100.00 100.00
Hamilton, KS
Frease, E. M. 2-20 20-26S-39W 036421 100.00 100.00
Hamilton, KS
Frease, E. M. 3-25 25-25S-39W 036422 50.00 50.00
Hamilton, KS
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
Delivery Point/ Meter Working Percent of
Well Name Location No. Interest Ownership
- ---------------- ------------ ------- --------- ----------
<S> <C> <C> <C> <C>
Hattrup, L. J. 1 30-26S-39W 043310 100.00 100.00
Hamilton, KS
Hattrup 2-30 30-26S-39W 043290 100.00 100.00
Hamilton, KS
Heltemes, N. A. 1 19-26S-39W 044160 100.00 100.00
Hamilton, KS
Heltemes, N. A. 2 36-26S-40W 044210 100.00 100.00
Hamilton, KS
Heltemes, N. A. 3 25-26S-40W 044260 100.00 100.00
Hamilton, KS
Heltemes 1-36 36-26S-40W 044140 100.00 100.00
Hamilton, KS
Heltemes 4-19 19-26S-39W 044143 100.00 100.00
Hamilton, KS
Heltemes 5-25 25-26S-40W 044144 100.00 100.00
Hamilton, KS
Hoffman, C. A. 1 16-26S-39W 046460 100.00 100.00
Hamilton, KS
Hoffman, C. A. 2-16 16-26S-39W 046340 100.00 100.00
Hamilton, KS
Lampe, John 1 08-26S-39W 054940 100.00 100.00
Hamilton, KS
Lampe Inc. 2-8 08-26S-39W 054900 100.00 100.00
Hamilton, KS
Lampe John Inc. 1 10-26S-39W 054990 100.00 100.00
Hamilton, KS
Lowenburg 1-7 07-26S-39W 068570 100.00 100.00
Hamilton, KS
Rector, Oscar 1 04-26S-39W 078930 100.00 100.00
Hamilton, KS
Rector 2-4 04-26S-39W 078929 100.00 100.00
Hamilton, KS
Stucky, Martin 1 17-26S-39W 091650 100.00 100.00
Hamilton, KS
Stucky 2-17 17-26S-39W 091651 100.00 100.00
Hamilton, KS
Yingling, Effie R. 1 36-25S-39W 099850 100.00 200.00
Hamilton, KS
Baughman, J. W. C 1 35-27S-34W 007070 25.00 25.00
Haskell, KS
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
Delivery Point/ Meter Working Percent of
Well Name Location No. Interest Ownership
- ---------------- ------------ ------- --------- ----------
<S> <C> <C> <C> <C>
Burton, T. C. 1 06-29S-34W 021770 50.00 50.00
Haskell, KS
Burton A-2 06-29S-34W 021780 50.00 50.00
Haskell, KS
Eubank, M. H. 1 33-28S-34W 032270 100.00 100.00
Haskell, KS
Eubank, M. H. A-1 28-28S-34W 032020 50.00 50.00
Haskell, KS
Eubank, M. H. B-1 23-28S-34W 032120 50.00 50.00
Haskell, KS
Eubank, M. H. C-1 07-28S-34W 032170 50.00 50.00
Haskell, KS
Eubank C-4 07-28S-34W 032173 50.00 50.00
Haskell, KS
Green, C. E. C-1 30-28S-34W 039630 50.00 50.00
Haskell, KS
Green C-2 30-28S-34W 039631 50.00 50.00
Haskell, KS
Gregg, E. M. #1 04-29S-34W 039930 50.00 50.00
Haskell, KS
Gregg 8-32 32-28S-34W 039933 100.00 100.00
Haskell, KS
Home Royalty Co. 1 15-28S-34W 046660 50.00 50.00
Haskell, KS
Jones, J. E. C-1 03-28S-34W 051110 50.00 50.00
Haskell, KS
Laird, C. C. B-1 30-28S-34W 054690 50.00 50.00
Haskell, KS
Lemon, J. C. A-1 24-28S-34W 055390 50.00 50.00
Haskell, KS
Lemon, J. C. B-1 25-28S-34W 055440 50.00 50.00
Haskell, KS
Lemon, J. C. C-1 09-29S-33W 055490 50.00 50.00
Haskell, KS
McCoy, Frank 1 32-28S-34W 064480 100.00 100.00
Haskell, KS
Onions A 1-2 02-29S-34W 075060 56.25 56.25
Haskell, KS
Orth, W. E. 1 21-28S-33W 075110 50.00 50.00
Haskell, KS
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
Delivery Point/ Meter Working Percent of
Well Name Location No. Interest Ownership
- ---------------- ------------ ------- --------- ----------
<S> <C> <C> <C> <C>
Pickens, Wm C. 1 31-28S-34W 076760 50.00 50.00
Haskell, KS
Pickens A-2 31-28S-34W 076751 50.00 50.00
Haskell, KS
Rahenkamp, E. W. 1 03-29S-34W 078030 50.00 50.00
Haskell, KS
Rahenkamp A 2 03-29S-34W 078035 50.00 50.00
Haskell, KS
Roy, Frank 3 27-27S-33W 080070 100.00 100.00
Haskell, KS
Roy, Frank 4 34-27S-33W 080110 100.00 100.00
Haskell, KS
Roy, Frank 6 33-27S-33W 080190 100.00 100.00
Haskell, KS
Stonestreet C 10-28S-34W 090870 50.00 50.00
Haskell, KS
Wheatley, J. S. 1 06-29S-33W 096810 100.00 100.00
Haskell, KS
Winsted, H. E. 1 29-28S-34W 098410 100.00 100.00
Haskell, KS
Winsted 2-29 29-28S-34W 098413 100.00 100.00
Haskell, KS
Bakke-Wiatt 1-A 09-24S-38W 003340 37.50 37.50
Kearney, KS
Burnett 1-A 17-24S-38W 021471 50.00 50.00
Kearney, KS
Swank 1-A 21-24S-38W 091850 12.50 12.50
Kearney, KS
Adams, A. W. M-2 33-34S-30W 000710 25.00 25.00
Meade, KS
Baughman 3-16 16-27S-40W 006980 100.00 100.00
Stanton, KS
Baughman J. W. 2 16-27S-40W 006970 100.00 100.00
Stanton, KS
Baughman 6-16 05-28S-40W 006990 100.00 100.00
Stanton, KS
Collingwood, A. J. 1 22-27S-40W 026790 100.00 100.00
Stanton, KS
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
Delivery Point/ Meter Working Percent of
Well Name Location No. Interest Ownership
- ---------------- ------------ ------- --------- ----------
<S> <C> <C> <C> <C>
Cooper, E. D. 1 08-28S-40W 027090 100.00 200.00
Stanton, KS
Cross, J. L. 2 32-27S-40W 028390 100.00 100.00
Stanton, KS
Dennis B 1-1 08-28W-40W 029450 56.24 56.24
Stanton, KS
Floyd, Eugene 1 09-28S-40W 035720 100.00 100.00
Stanton, KS
Floyd 2-9 09-28S-40W 035721 100.00 100.00
Stanton, KS
Floyd 3-9 06-28S-40W 035722 100.00 100.00
Stanton, KS
Fraser, Nellie E 1 30-27S-40W 036270 100.00 100.00
Stanton, KS
Mohney, E 2-34 34-27S-40W 070761 100.00 100.00
Stanton, KS
Mohney, Eugene 1 34-27S-40W 070760 100.00 100.00
Stanton, KS
Smith, Abbie E 1 26-27S-40W 086010 100.00 100.00
Stanton, KS
Smith, A. E. 2-26 26-27S-40W 086011 100.00 100.00
Stanton, KS
Timm, R. K. 1 27-27S-40W 093200 100.00 100.00
Stanton, KS
Williamson, Mary C. 1 29-27S-40W 097810 100.00 100.00
Stanton, KS
Wilson, D. R. 1-22 22-27S-40W 097912 100.00 100.00
Stanton, KS
Winger, Clarence 2 28-27S-40W 098110 100.00 100.00
Stanton, KS
Winger, Clarence 1 33-27S-40W 098060 100.00 100.00
Stanton, KS
Winger, Clarence 3 04-27S-40W 098160 100.00 100.00
Stanton, KS
Winger, Clarence 4 21-28S-40W 098210 100.00 100.00
Stanton, KS
Winger, Clarence 5 35-27S-40W 098260 100.00 100.00
Stanton, KS
Winger, C. 10-33 33-27S-40W 098265 100.00 100.00
Stanton, KS
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
Delivery Point/ Meter Working Percent of
Well Name Location No. Interest Ownership
- ---------------- ------------ ------- --------- ----------
<S> <C> <C> <C> <C>
Winger, C. 11-4 04-28S-40W 098266 100.00 100.00
Stanton, KS
Winger, C. 6-35 35-27S-40W 098261 100.00 100.00
Stanton, KS
Winger, C. 7-27 27-27S-40W 098262 100.00 100.00
Stanton, KS
Winger, C. 8-21 21-27S-40W 098263 100.00 100.00
Stanton, KS
Winger, C. 9-28 28-27S-40W 098264 100.00 100.00
Stanton, KS
Winger, T. R. 1 23-27S-40W 098310 75.00 75.00
Stanton, KS
Winger, T. R. 2-23 23-27S-40W 098311 75.00 75.00
Stanton, KS
Adams, R E 8 23-6N-24ECM 001410 50.00 50.00
Beaver, OK
Adams, R E 11 30-6N-25ECM 001460 37.50 37.50
Beaver, OK
Adams 1-20 20-6N-25ECM 00252 50.00 50.00
Beaver, OK
Adams 1-31 (St. Louis) 31-06N-25ECM 000330 50.00 50.00
Beaver, OK
Adams A-5 (Che) 36-06N-24ECM 000430 50.00 50.00
Beaver, OK
Adams A-5 (SG) 36-06N-24ECM 000440 50.00 50.00
Beaver, OK
Adams B 4 36-06N-24ECM 000450 50.00 50.00
Beaver, OK
Baldwin 1 07-05N-25ECM 003349 25.48 25.48
Beaver, OK
Barby, Fred 1 36-05N-25ECM 005220 100.00 100.00
Beaver, OK
Barby, Fred 2 31-05N-26ECM 005270 87.50 87.50
Beaver, OK
Barby, Lloyd 1 10-04N-25ECM 005580 100.00 100.00
Beaver, OK
Barby, Lloyd 2 22-04N-25ECM 005420 100.00 100.00
Beaver, OK
Barby, Otto 1 34-05N-26ECM 006170 43.75 43.75
Beaver, OK
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
Delivery Point/ Meter Working Percent of
Well Name Location No. Interest Ownership
- ---------------- ------------ ------- --------- ----------
<S> <C> <C> <C> <C>
Barby, Otto A-1 25-05N-25ECM 006270 15.00 15.00
Beaver, OK
Carlisle, H 16-22 C 22-03N-28ECM 024718 50.00 50.00
Beaver, OK
Carlisle, H. 16-22 M 22-03N-28ECM 024719 50.00 50.00
Beaver, OK
Carlisle, H. 10-A 22-03N-28ECM 024660 50.00 50.00
Beaver, OK
Carlisle, H. 11 22-03N-28ECM 024690 50.00 50.00
Beaver, OK
Carlisle, H. 1-10 10-03N-28ECM 024140 50.00 50.00
Beaver, OK
Carlisle, H. 3 16-03N-28ECM 024290 100.00 100.00
Beaver, OK
Carlisle, H. 4 15-03N-28ECM 024230 100.00 100.00
Beaver, OK
Carlisle H. 6 21-03N-28ECM 024490 34.36 34.36
Beaver, OK
Carlisle, H. 8 16-03N-28ECM 024540 100.00 100.00
Beaver, OK
Carlisle 13-15 (Chester) 15-03N-28ECM 024715 100.00 100.00
Beaver, OK
Carlisle 13-15 (Morrow) 15-03N-28ECM 024714 100.00 100.00
Beaver, OK
Carlisle 14-16 LT 16-03N-28ECM 024712 100.00 100.00
Beaver, OK
Carlisle 14-16 UT 16-03N-28ECM 024173 100.00 100.00
Beaver, OK
Carlisle 15-14 14-03N-28ECM 024717 25.00 25.00
(Chester/MO) Beaver, OK
Carlisle 17-21 21-03N-28ECM 024716 34.92 34.92
Beaver, OK
Carlisle 5 (Hoover) 23-03N-28ECM 024390 100.00 100.00
Beaver, OK
Carlisle H. 12-10 10-03N-28ECM 024710 57.14 57.14
Beaver, OK
Evans, E. E. 1 (Chester) 08-05N-25-ECM 033120 50.00 50.00
Beaver, OK
Evans, E. E. 1 (Morrow) 08-05N-25ECM 033221 50.00 50.00
Beaver, OK
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
Delivery Point/ Meter Working Percent of
Well Name Location No. Interest Ownership
- ---------------- ------------ ------- --------- ----------
<S> <C> <C> <C> <C>
Judy 1 (WYAND) 06-05N-25ECM 25.00 25.00
Beaver, OK
July 4-6 06-05N-25ECM 051305 100.00 100.00
Beaver, OK
Judy A 2-6 06-05S-25W 051380 50.00 50.00
Beaver, OK
Judy B 1-5 05-05S-25W 051410 37.50 37.50
Beaver, OK
Kamas 1-15 15-05N-25ECM 051970 63.00 63.00
Beaver, OK
Kamas 2-15 15-05N-25ECM 051975 67.24 67.24
Beaver, OK
Mayo, Nina 1-18 18-04N-25ECM 062480 68.75 68.75
Beaver, OK
Mayo, Nina 2 07-04N-25ECM 062560 100.00 100.00
Beaver, OK
Mayo, Nina 3 06-04N-25ECM 062640 100.00 100.00
Beaver, OK
Mayo, Nina 4 01-04N-24ECM 062720 100.00 100.00
Beaver, OK
Mulberry 1 (HOOV) 26-03N-28ECM 072160 6.67 6.67
Beaver, OK
Overton 06-03N-26ECM 075210 50.00 50.00
Beaver, OK
Raymond 2 31-06N-25ECM 078590 25.00 25.00
Beaver, OK
USA Unit 05-04N-25ECM 094260 100.00 100.00
Beaver, OK
Cole 1 15-04N-9ECM 026540 25.00 25.00
Cimmarron, OK
Hager, A. H. 1 36-06N-08ECM 041260 25.00 25.00
Cimmarron, OK
Ross, M. B. 2 28-05N-09ECM 079952 33.33 33.33
Cimmarron, OK
Ross, M. B. 3 28-05N-09ECM 079953 33.33 33.33
Cimmarron, OK
Wiggins 1 23-04N-8ECM 097410 83.20 83.20
Cimmarron, OK
Hamilton, Ella 06-05N-10ECM 042510 75.00 75.00
Texas, OK
</TABLE>
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
Delivery Point/ Meter Working Percent of
Well Name Location No. Interest Ownership
- ---------------- ------------ ------- --------- ----------
<S> <C> <C> <C> <C>
ANR Pipeline Co. Beaver Co., OK Int. Various Various
(Beaver) 31-5N-21E 9911221
Northern Natural Gas Co. Finney Co., KS Int. Various Various
(Meadowlark) (Note 1) 3-24S-34W 991664100
Transwestern Pipeline Co. Sherman Co., TX Int. Various Various
(Tumbleweed) (Note 1) 991489000
Panhandle Eastern Pipe Kearney Co., KS Int. Various Various
Line Co. 29-24S-36W 991118000
(Lakin) (Note 1)
Northern Natural Gas Co. Moore Co., TX Int. Various Various
(Dumas) (Note 1) 99112900
Natural Gas Pipeline Co. Beaver Co., OK Int. Various Various
of America 29-5N-23E 991044000
(Forgan) (Note 1)
El Paso Natural Gas Co. Moore Co., TX Int. Various Various
(Big Blue) (Note 1) 991291000
Other Hugoton Infill
Wells As Connected
</TABLE>
Note 1: Delivery of gas by displacement only.
<PAGE>
<PAGE>
AMENDMENT TO
OPERATING AGREEMENT
This Amendment to the OPERATING AGREEMENT dated January 8, 1988, by
and between MESA OPERATING LIMITED PARTNERSHIP (hereinafter referred to as
("MESA"), and COLORADO INTERSTATE GAS COMPANY (hereinafter referred to as
"CIG") is entered into and effective as of October 1, 1988.
WHEREAS, MESA and CIG executed an Operating Agreement on the 8th day
of January, 1988; and
WHEREAS, MESA and CIG now wish to amend Exhibit "C", Accounting
Procedure, to the Operating Agreement.
NOW, THEREFORE, the Parties agree as follows:
1. Article III. ADMINISTRATIVE FEES, Paragraph 3.1 Authorized
Payments and Charges, Paragraph A of the Accounting Procedure (Exhibit "C"
to the Operating Agreement) is hereby amended to read as follows:
All leasehold royalties, overriding royalties and other payments out
of production from wells subject to the Operating Agreement. The
following royalty payments shall be billed in full to MESA without
allocation: (1) royalty payments under Paragraph 2(a) of the
"Compromise and Settlement Agreement" in Cause No. CA-2-76-131 dated
as of December 31, 1981 between Amarillo Oil Company ("AOC"), CIG and
the royalty owners defined therein as "Lessor" and the contemporaneous
letter agreement between AOC and CIG: (2) royalty payments under
paragraph 2(a) of the "Compromise and Settlement Agreement" in Cause
No. CA-2-75-68 dated as of December 31, 1981, between AOC, CIG and the
royalty owners defined therein as "Lessor"; and (3) royalty payments
defined as "MESA Additional Royalty" in the "Accounting Agreement"
attached as Exhibit "A" to the "Royalty Agreement" dated October 1,
1988, between MESA, CIG and the royalty owners defined therein as
"Lessor."
Except as amended herein, the Operating Agreement dated the 8th day of
January, 1988, including the Accounting Procedure attached thereto as
Exhibit "C", shall remain in full force and effect.
<PAGE>
WHEREFORE, the parties hereto have executed this Amendment this _____
day of November, 1989.
COLORADO INTERSTATE GAS COMPANY
Attest:
- ------------------------------ By /s/ C. S. Hobbs
----------------------------
C. S. Hobbs, Senior Vice President
MESA OPERATING LIMITED PARTNERSHIP
By Pickens Operating Company, the
General Partner
Attest:
- ------------------------------ By -------------------------------
<PAGE>
(COLORADO INTERSTATE GAS COMPANY LOGO AND STATIONERY)
C. Scott Hobbs
Senior Vice President (Stationery Heading)
July 15, 1990
Claude B. Jenkins
Vice President-Marketing
Mesa Operating Limited Partnership
One Mesa Square
P. O. Box 2009
Amarillo, TX 79189-2009
Re: Amendment to Gathering Agreement
Dated July 15, 1990
Dear Claude:
This letter is to confirm the agreement of Colorado Interstate Gas Company
("CIG") and Mesa Operating Limited Partnership ("Mesa') concerning the
referenced Amendment.
CIG and Mesa agree that Mesa may deliver volumes of gas, at a daily rate of
flow up to 10 MMcfd, to CIG from July 15 through October 31, 1990, as a
partial payment in kind for Mesa's pro rata share of fuel gas to be used in
calendar year 1990. Mesa shall deliver any such fuel reimbursement volumes
from its or Mesa Midcontinent Limited Partnership's interests in Oklahoma
which are currently connected to CIG, and from any other mutually agreeable
delivery points listed on Exhibit "A" to the Amendment to the Gathering
Agreement, dated July 15, 1990. Mesa shall also provide daily and monthly
volume nominations for any fuel reimbursement volumes delivered to CIG
during this period. These volume nominations shall be consistent with
Article VI of the Storage Service Agreement between CIG and Mesa dated July
15, 1990.
Mesa shall pay, based on CIG's WACOG, for its pro rata share of fuel
actually used during the calendar year 1990 which was not delivered as a
payment in kind referenced above. Mesa's payments based on CIG's WACOG
shall be consistent with the terms more fully described for purchased fuel
volumes in the referenced Amendment.
<PAGE>
If the foregoing is in accordance with Mesa's understanding of our
agreement, please so indicate by signing in the space provided below and
returning one original for our file.
Sincerely,
COLORADO INTERSTATE GAS COMPANY
By: /s/ C. Scott Hobbs
---------------------------
C. Scott Hobbs
Senior Vice President
CSH:sjm
Accepted and agreed to
this 11th day of July, 1990.
---- ----
MESA OPERATING LIMITED PARTNERSHIP,
Acting On Behalf of Itself and
As Agent for Mesa Midcontinent
Limited Partnership
By: Pickens Operating Co.,
General Partner
By: /s/ Claude B. Jenkins
------------------------------
Claude B. Jenkins
Vice President - Marketing
GAS PURCHASE AGREEMENT
between
MESA OPERATING CO.
as "Seller"
and
KN Marketing, L.P.
as "Buyer"
Dated: January 1, 1996
Potter, County
State of Texas
<PAGE>
TABLE OF CONTENTS
ARTICLE PAGE
- ------- ----
I Definitions 1
II Quantity 3
III Term 4
IV Price 5
V Point(s) of Delivery 6
VI Delivery Pressure 6
VII Quality 7
VIII Measuring Equipment and Testing 8
IX Measurement Specifications 12
X Billings and Payments 14
XI Sale and Passage of Title 15
XII Warranty of Title 16
XIII Force Majeure 16
XIV Governmental Authorizations 18
XV Indemnification 19
XVI Assignments 19
XVII Royalty 18
XVIII Notices 20
XIX Taxes 20
XX Miscellaneous 21
Signatures 23
<PAGE>
GAS PURCRASE AGREEMENT
THIS AGREEMENT, made and entered into as of the ist day of January,
1996, ("Effective Date") by and between KN MARKETING, L.P., a Texas Limited
Partnership, ("Buyer") , and Mesa Operating Co., ("Seller").
W I T N E S S E T H:
WHEREAS, Buyer is in the business of marketing natural gas and
requires natural gas to meet the needs of its customers in the City of
Amarillo, its environs and other customers;
WHEREAS, Seller operates a natural gas processing plant known as the
Fain Plant in Potter County, Texas and has or may have quantities of gas
available for sale in excess (1)of the quantities of gas needed to supply
Energas Company ("Energas") and other customers for consumption in the City
of Amarillo and its environs, and (2) up to two thousand (2,000) MMcf per
year beginning January 1, 1997 and for the remaining term of this Agreement
for Liquefied Natural Gas (LNG) supply requirements, and;
WHEREAS, Seller desires to sell such excess gas to Buyer and Buyer
desires to purchase such excess gas from Seller;
NOW, THEREFORE in consideration of the mutual covenants contained
herein, and other good and valuable consideration, the parties do hereby
covenant and agree as follows:
ARTICLE I
DEFINITIONS
-----------
As used in this Agreement, the following terms and phrases shall have
the respective meanings ascribed to them below, unless the context clearly
requires a different meaning.
1.1 "Cubic Feet" or "cubic foot" means the volume of gas which
occupies one (1) cubic foot of space at a temperature of sixty degrees
(600) Fahrenheit and an absolute pressure of fourteen and sixty-five
hundredths (14.65) pounds per square inch absolute ("Psia").
1.2 "Mcf" means one thousand (1, 000) cubic feet of gas, Mmcf means
one million (1,000,000) cubic feet of gas, and "Bcf" shall mean one billion
(1,000,000,000) cubic feet of gas.
1.3 "Btu" (British thermal unit) means the amount of heat required to
raise the temperature of one avoirdupois pound of pure water from
fifty-eight and five tenths degrees (58.5 degrees) Fahrenheit to fifty-nine
and five tenths degrees (59.5 degrees) Fahrenheit at a constant pressure of
fourteen and seventy-three hundredths (14.73) Psia. Where appropriate, Btu
shall mean the plural of the aforementioned definition. The term "MMBtu"
shall mean one million (1,000,000) Btu.
1.4 "Gross Heating Value" means the number of Btu's liberated by the
complete combustion at constant pressure of one (1) cubic foot of gas, at a
base temperature of sixty degrees (60 degrees) Fahrenheit and a referenced
pressure base of fourteen and sixty-five hundredths (14.65) Psia, with air
of the same temperature and pressure of the gas, after products of
combustion are cooled to the initial temperature of the gas, and after the
water of the combustion is condensed to the liquid state. The Gross
Heating Value of the gas shall be calculated on a saturated basis, with the
results adjusted to reflect the actual water vapor content of the gas as
delivered.
1.5 "Day" means a period of twenty-four (24) consecutive hours
beginning and ending at seven (7:00) o'clock a.m. Central Time ("CT"). The
reference date for any day shall be the calendar date upon which such
twenty-four (24) hour period began.
1.6 "Month" means a period beginning at seven (7:00) o'clock a.m. CT
on the first day of a calendar month and ending at seven (7:00) a.m. CT on
the first day of the calendar month immediately following.
1.7 "Year" means a period consisting of three hundred sixty five
(365) consecutive days, commencing and ending at seven (7:00) o'clock a.m.
CT; provided, however, that any such year which contains the date of
February twenty-nine (29) shall consist of three hundred sixty six (366)
consecutive days.
ARTICLE II
QUANTITY
--------
2.1
A. Subject to the provisions of subparagraphs B., C. and D.
below, Seller agrees to tender for delivery and sale to Buyer and Buyer
agrees to receive and purchase hereunder all gas Seller has available for
sale at the Delivery Points in excess of any gas required by Seller's
Priority Customers (defined below), and in excess of the Reserved Gas
(defined below), and reserved by Seller for its LNG supply requirements.
Notwithstanding the preceding sentence to the contrary, Seller and Buyer
recognize that in the event of sudden or extreme volume changes in either
Seller's supply or Buyer's markets, Buyer may need reasonable lead time
to adjust its gas supply or markets to accommodate such sudden or extreme
volume changes to enable Buyer to purchase gas volumes made available
hereunder, by Seller. Buyer agrees to use its best efforts to minimize
the lead time necessary to accommodate such volume changes. However, in
no instance shall Buyer take more than five (5) working days to make such
supply or market adjustments. Failure of gas markets is not cause for
nonperformance by either party under the terms of this Agreement.
B. Buyer recognizes that Seller must satisfy its gas supply
obligations to Energas, as well as other customers which were receiving gas
from Seller's Fain Plant either directly or indirectly as of January 1,
1995, listed in Exhibit "A" attached hereto and made a part hereof
('Seller's Priority Customers').
C. Buyer recognizes that Seller expects to construct and operate an
LNG plant in conjunction with its Fain Plant and hereby reserves up to two
thousand (2,000) MMcf of residue gas each year commencing January 1, 1997
to satisfy its LNG supply requirements ("Reserved Gas").
D. Buyer recognizes that Seller's Priority Customers have a first
call on all gas Seller has available at the tailgate of the Fain Plant and
that Seller has reserved up to two thousand (2,000) Mmcf per year
additional gas commencing January 1, 1997; accordingly, Buyer expressly
acknowledges that on any given day Seller may be unable to deliver any gas
to Buyer hereunder.
2.2 Seller will consult with Buyer as often as necessary regarding
Seller's projection of the volume of gas to be available for delivery to
Buyer during each month. Such projection will be based upon the volume of
gas Seller expects to have available for delivery to Buyer after satisfying
the requirements of Seller's Priority Customers and LNG markets. Seller
will also provide to Buyer at least fifteen (15) days prior to the
beginning of each month, a forecast of the volumes of gas it expects to
have available for delivery to Buyer during each of the next twelve (12)
months.
2.3 It is the intent of Buyer and Seller that all of the gas
delivered hereunder be ultimately consumed in the City of Amarillo and its
nvirons to the maximum extent practicable. Accordingly, it is expressly
understood and acjreed that all gas delivered hereunder shall be allocated
by Buyer to Buyer's markets in the City of Amarillo and its environs before
Buyer allocates any gas from other sources to such markets. Buyer shall
provide Seller with a statement on a quarterly basis showing the volume of
gas purchased hereunder from Seller and the total volume of gas delivered
to Buyer's markets in the City of Amarillo and its environs.
ARTICLE III
TERM
----
3.1 This Agreement shall become effective, regardless of when
executed, on the Effective Date hereof and continue for a term ending on
the 31st day of December 1999 ("Primary Term"), and continuing year to year
thereafter until canceled by either party giving the other party sixty (60)
days written notice prior to the end of the Primary Term, or any succeeding
year thereafter.
ARTICLE IV
PRICE
-----
4.1 Buyer shall pay Seller for natural gas purchased and
received by Buyer hereunder each month a total price per MMBTU dry,
inclusive of any and all taxes and transportation charges, equal to Index
Price plus two cents ($0.02):
Where:
Index Price= the arithmetic average of the gas prices listed
under the column titled "Index" in the first issue of the month
when deliveries of gas are made, of Inside F. E. R. C. Gas Market
Report (GMR), in the table titled "Prices of Spot Gas Delivered
to Pipelines" for Transwestern Pipeline Co. Permian Basin,
El Paso Natural Gas Co. - Permian Basin, Panhandle Eastern
Pipe Line Co.- Texas, Oklahoma (mainline), Natural Gas Pipeline
Co. of America - Oklahoma, and Williams Natural Gas Co.
Texas, Oklahoma, Kansas.
4.2 If GMR ceases to report a price for a designated pipeline which
is used in determining the Index Price under Paragraph 4.1 above, then the
price for the same pipeline listed in Natural Gas Week, published by The
----------------
Oil Daily Co., in the table titled "Spot Prices on Interstate Pipeline
Systems", "Delivered-to-Pipelinell in the column labeled "This Week" for
the Transwestern Pipeline Co. Permian: Ward County, Texas, Natural Gas
Pipeline Co. of America - Forgan, Oklahoma, El Paso Natural Gas Co. -
Anadarko: Washita County, Oklahoma, Panhandle Eastern Pipe Line Co. -
Kansas/Oklahoma Field Zone, and the Williams Natural Gas Co. - Mainline,
Kansas/Oklahoma as reported in the first issue each month when deliveries
of gas are made will be substituted therefor.
4.3 If the total number of published pipelines referenced in
Paragraphs 4.1 and 4.2 above is less than three (3), then the parties shall
utilize a source of monthly price quotes as nearly as comparable to the
Index Price postings described in Paragraph 4.1 above as possible to
determine the actual Index Price in effect for each month.
ARTICLE V
POINT(S) OF DELIVERY
--------------------
5.1 The delivery of gas hereunder shall be made at the following
"Delivery Points":
A) at the outlet of Energas' meter in Section 97, Block 1,
BS & F Survey, Potter County, Texas, known as the "Nichols
Station Energas Delivery Point";
B) at the inlet of Buyer's or Buyer's designee's meter in the
SW/4 of Section 20, G & M Survey, Block M-3, Potter County,
Texas, known as the "Amarillo Creek Interconnect";
C) at the inlet of Buyer's or Buyer's designee's meter in
Section 81, Block 3, G & M Survey, Potter County, Texas, known as
the "Fain Plant Interconnect";
or
D) any other mutually agreed to point(s).
5.2 Buyer and Seller recognize that Seller has a prior obligation to
deliver a certain minimum volume of gas each year through the pipeline
facilities of Energas. Accordingly, such minimum volume of gas will be
delivered by Seller to Buyer at the Delivery Points described in 5.1 A) or
B) above.
ARTICLE VI
DELIVERY PRESSURE
-----------------
6.1 Subject to the provisions of Paragraph 6.2 below, Seller shall
deliver the gas, or cause such gas to be delivered, at the Delivery
Point(s) at a pressure sufficient to enter Buyer's or its designee's
facilities against the working pressure(s) maintained therein from time to
time but not in excess of the pressure that normally exists at the Delivery
Point(s); provided, however, Seller shall not be required to deliver gas
to Buyer at a pressure greater than the current maximum plant discharge
pressure of three hundred eighty (380) psig. Seller shall not be obligated
to install additional compression facilities in order to deliver gas
hereunder.
Notwithstanding any other provision of this Agreement, Seller shall
never deliver gas at a pressure that exceeds the maximum allowable working
pressure(s), as determined solely by Buyer or Buyer's designee.
6.2 Buyer at its sole cost and expense shall provide or cause to be
provided, all compression facilities required to transport all volumes of
gas to the Westar Transmission Company (Westar) system which are in excess
of Buyer's requirements on Westar's twenty inch (2011) Moore County
pipeline.
6.3 In the event Seller or Buyer or their respective designee
installs compression, the installation and operation of such compression
shall not adversely affect the accurate measurement of the gas delivered
hereunder. In the event such compression adversely affects such
measurement of gas, the affected party or its designee shall have the right
to suspend the receipt of gas hereunder only at that specific Delivery
Point until such condition is corrected.
ARTICLE VII
Quality
-------
7.1 The gas delivered at the Delivery Point(s) shall be of pipeline
quality and:
(a contain not more than one-fourth (h) grain of hydrogen sulfide
per one hundred (100) cubic feet;
(b) contain not more than five (5) grains of total sulfur per one
hundred (100) cubic feet;
(c) contain not more than two percent (2%) by volume of carbon
dioxide;
(d) shall have a Gross Heating Value of not less than nine hundred
and fifty (950) Btu's per cubic foot;
(e) contain no free liquids;
(f) contain not more than one percent (1%) by volume of oxygen;
(g) contain not more than seven (7) pounds of water vapor per one
million (1, 000, 000) cubic feet provided, however, if the gas
contains seven (7) pounds or less of water vapor per one million
(1,000,000) cubic feet, it shall be deemed dry.
(h) be commercially free of dust, gums, dirt, impurities and other
solids;
(i) not have a temperature of less than forty degrees (400)
Fahrenheit nor more than one hundred twenty degrees (1200)
Fahrenheit;
(j) contain not more than twelve percent (12%) by volume of nitrogen;
Buyer shall have the right to either (i) accept gas that does not conform
to the above specifications, or (ii) refuse delivery of such gas that does
not conform to the above specifications. Buyer or Buyer's designee's
acceptance of gas that does not conform to the quality specifications set
forth above shall not constitute a waiver of such specifications by Buyer
in regard to gas delivered by Seller hereunder in the future.
ARTICLE VIII
MEASURING EOUIPMENT AND TESTING
-------------------------------
8.1 Each of the parties hereto acknowledges and agrees that the
measuring facilities currently located at the Delivery Point(s) shall be
the "Official Billing Measurement Station" for purposes of this Agreement
and that the owner of such Official Billing Measurement Station (the
"Operator"), or such other party as the Operator and Buyer (in the event
Buyer is not the operator) may mutually designate, shall perform the
reading, calibrating, and adjusting of, and the changing of charts on, the
equipment in the official Billing Measurement Station and shall perform all
gas analysis relating to the gas delivered hereunder.
8.2 Orifice meters installed in such measuring stations shall be
constructed and operated in accordance with American National Standard
Institute ("ANSI")/American Petroleum Institute ("API'l) 2530, American Gas
Association ("AGA") Report No. 3), Orifice Metering of Natural Gas and
-----------------------------------
Other Related Hydrocarbon Fluids, Second Edition, dated September 1985, and
- --------------------------------
shall include the use of flange connections and, where necessary,
straightening vanes and pulsation dampening equipment.
8.3 When and where electronic measurement and flow computers are
utilized, the gas received hereunder may have its volume, mass, gravity,
composition and/or energy content determined and computed in accordance
with applicable AGA standards including, but not limited to, AGA Report No.
3, 1985 edition, AGA Report No. 5, 1983 edition, AGA Report No. 6, 1971
edition, and AGA Report No. 7, 1984 edition. The parties agree to use and
accept the electronic derivations, measurements and calculations in lieu of
mechanical recordings, chart integration and subsequent calculations.
8.4 Operator shall give reasonable notice to non-operator in order
that non-operator may have representatives present to observe any
installing, reading, cleaning, changing, repairing, inspecting, testing,
calibrating, or adjusting of Operator's measuring equipment used in
measuring or checking the measurement of receipts or deliveries of gas
under this Agreement. The official charts (recordings) from such measuring
equipment shall remain the property of Operator, but upon request Operator
will submit its records and charts, together with calculations therefrom,
to nonoperator for inspection and verification, subject to return to
operator within thirty (30) days after receipt thereof.
8.5
A. Operator shall, in the presence of non-operator's representative,
if requested, verify the accuracy, adjust and calibrate all recording
devices used in the measurement of the receipt of gas hereunder on at least
a monthly basis. operator shall not be required to, but may elect to,
adjust or calibrate such equipment more frequently than specified above,
unless non-operator desires a special test be performed as described in
Paragraph 8.6 below.
B. If during any test of the measuring equipment, an adjustment or
calibration error is found which results in an incremental adjustment to
the calculated hourly flow rate through each meter run in excess of two
percent (2%) of the correct flow rate (whether positive or negative and
using the correct flow rate as the percent error equation denominator), then
any previous recording of such equipment shall be corrected to zero (0)
error for any period which the error existed (and which is either known
definitely or agreed to by both parties) and the total flow for the period
redetermined in accordance with the provisions of Paragraph 8.7 below. If
the period of error condition cannot be determined or agreed upon between
the parties, such correction shall be made over a period extending over the
last one-half (1/2) of the time elapsed since the date of the latest test,
such correction period not to exceed fifteen (15) days.
C. If, during any test of the measuring equipment, an adjustment or
calibration error is found which results in an incremental adjustment to
the calculated hourly flow rate which does not exceed two percent (2%) of
the adjusted flow rate (as described in part (B.) of this Section), all
prior recording shall be considered to be accurate for quantity
determination purposes.
D. If, during any test of the measuring equipment, an adjustment or
calibration error is found, the measuring equipment shall be adjusted at
once to measure properly and accurately.
8.6 In the event non-operator desires a special test (a test not
scheduled by Operator under the provision of Paragraph 8.5 above) of any
measuring equipment, seventy-two (72) hours advance notice in writing shall
be given to Operator and both parties shall cooperate to secure a prompt
test of the accuracy of such equipment. If the measuring equipment tested
is found to fall under the provisions of Paragraph 8.5 C. above or if an
inspection of the primary measurement equipment indicates no problems,
operator shall have the right to bill non-operator for the cost of such
special test including any labor and transportation costs pertaining to
such special test and Non-operator shall pay such costs.
8.7 If, for any reason, any measurement equipment is (I) out of
adjustment, (ii) out of service, or (iii) out of repair and the total
calculated hourly flow rate through each meter run is found to be in error
by an amount of the magnitude described in Paragraph 8.5 B. above, the
total quantity of gas delivered shall be redetermined in accordance with
the first of the following methods which is feasible:
(a) by using the registration of any mutually agreeable check
metering facility, if installed and accurately registering
(subject to testing as described in Paragraph 8.5 above);
(b) where parallel multiple meter runs exist, by calculation using
the registration of such parallel meter runs; provided that they
are measuring gas from upstream and downstream headers in common
with the faulty metering equipment, are not controlled by
separate regulators, and are accurately registering;
(c) by correcting the error by re-reading of the official charts, or
by straightforward application of a correction factor to the
quantities recorded for the period (if the net percentage of
error is ascertainable by calibration, tests or mathematical
calculation);
(d) by estimating the quantity, based upon deliveries made during
periods of similar conditions when the meter was registering
accurately.
8.8 Operator shall retain and preserve for a period of at least two
(2) years all test data, charts, and other similar records.
8.9 To the extent permitted by the Operator, either Buyer or Seller
may install, maintain and operate check measuring instruments and
telemeters in, and connected to, the official, Billing Measurement Station
for purposes of checking the operator's meters; provided, however, that all
gas measurements required in this Agreement shall be determined by the
Operator's meters and further provided that such check measuring and
telemetering instruments and connections shall be installed so as not to
interfere with the operation or future modification of the operator's
official billing meters and appurtenances. Each party hereto agrees to
indemnify, defend, and hold harmless the other party from any and all
claims and liabilities incurred by such other party arising from the
installation, operation, maintenance, or March 1, 1996 removal by or for
the indemnifying party of such check measuring and telemetering instruments
to the Official Billing Measurement Station. Each party hereto shall have
access, at reasonable hours, upon giving the other party at least
twenty-four (24) hours prior written notice of its desire to obtain such
access, and to the extent permitted by the Operator, to such check
measuring and telemetering instruments installed by the other party, but
the reading, calibrating, and adjusting thereof and the changing of
charts thereon shall be performed by such other party.
ARTICLE IX
MEASUREMENT SPECIFICATIONS
--------------------------
The measurements of the quantity and quality of all gas delivered and
purchased hereunder shall be conducted in accordance with the following:
9.1 Unit of Volume: The unit of volume for measurement shall be one
--------------
(1) cubic foot of gas. Such measured volumes, converted to MCF, shall be
multiplied by their Gross Heating Value per cubic foot and divided by one
thousand (1,000) to determine MMbtus received and delivered hereunder.
9.2 Volume Computations: Computations of gas volumes from measurement
-------------------
data shall be made in accordance with ANSI/API 2530 (AGA Report No. 3),
Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids,
- --------------------------------------------------------------------
Second Edition, dated September 1985, and any subsequent amendments or
revision, as mutually agreed upon. If electronic devices and flow
computers are utilized, volumes will be determined in accordance with AGA
Committee Report No(s). 3, 5, 6, and 7, as specified in Paragraph 8.3 and
any subsequent amendments or revisions, as mutually agreed upon.
9.3 Temperature Measurement: The temperature of the gas shall be
determined electronically or by a recording thermometer so installed that
it may record the temperature of the gas flowing through the meters. If
the parties do not consider the installation of such a recording
thermometer to be necessary, other agreeable means of recording temperature
may be used. The average temperature to the nearest one (1 degree) degree
Fahrenheit, obtained while gas is being delivered, shall be the applicable
flowing gas temperature for the period under consideration.
9.4 Specific Gravity Measurement: At least quarterly, the specific
----------------------------
gravity of the gas shall be determined by a recording gravitometer or a
chromatographic device installed and located at a suitable point to record
representative average specific gravity of the gas being metered or by
other mutually agreeable methods. The gravity, to the nearest
one-thousandth (0.001), obtained while gas is being delivered shall be the
specific gravity of the gas used for the recording period. If Buyer and
Seller mutually agree, spot samples or continuous sampling using standard
type specific gravity sampling methods may be used in lieu of a recording
gravitometer or chromatograph. If the spot sample or continuous sampling
method is used, the specific gravity of the gas delivered hereunder shall
be determined from a gas analysis. The result shall be obtained to the
nearest one-thousandth (0.001) and shall be applied during the applicable
quarter or time period for the determination of gas volumes delivered.
9.5 Adjustment for Supercompressibility: At least quarterly,
-----------------------------------
adjustments to measured gas volumes for the effects of supercompressibility
shall be made in accordance with accepted AGA standards. Operator shall
obtain representative carbon dioxide and nitrogen mole fraction values for
the gas delivered or received as may be required to compute such
adjustments in accordance with standard testing procedures. If Buyer and
Seller mutually agree, equations for the calculation of
supercompressibility may be taken from either (I) the AGA Manual for the
--------------
Determination of Supercompressibility Factors for Natural Gas, dated
- -------------------------------------------------------------
December, 1962 (also known as the IINX-19 Manual") or (ii) the AGA Report
No. 8, dated December, 1985, Compressibility and Supercompressibility for
--------------------------------------------
Natural Gas and Other Hydrocarbon Gases, or any subsequent revision to AGA
- ---------------------------------------
Report No. 8.
9.6 Corrections: Appropriate corrections to the gas measurements
-----------
taken hereunder shall be made for deviation from the Ideal Gas Laws at the
pressures and temperatures at which the gas was delivered hereunder.
9.7 Assumed Atmospheric Pressure: An assumed atmospheric pressure of
thirteen and two tenths pounds per square inch absolute (13.2) Psia at the
delivery points shall be utilized for measurement and calculation purposes,
irrespective of any variation of the actual atmospheric pressure from the
assumed atmospheric pressure.
9.8 Gross Heating Value: The Gross Heating Value of the gas delivered
-------------------
at the Delivery Point hereunder shall be determined by using a
Cutler-Hammer or other standard type calorimeter or by calculating the
Gross Heating Value from an in-line chromatograph or a gas analysis of a
spot or continuous gas sample. The spot or continuous sample shall be
taken monthly and such sample shall be taken at a suitable point on the
facilities to be representative of the gas being metered.
9.9 Other Tests: Other tests to determine water content, sulfur, and
-----------
other impurities in the gas shall be conducted by Operator as necessary and
shall be conducted in accordance with standard industry testing procedures.
The party requested to perform such test(s) shall bear the cost of test(s)
only in the event the gas tested is determined not to be within the
applicable specification(s), otherwise the requesting party shall bear the
cost of such test(s).
9.10 New Test Methods: If at any time during the term hereof a new
----------------
method or technique is developed with respect to gas measurement, such new
method or technique may be substituted for the method set forth in this
Article when such methods or techniques are in accordance with the
currently accepted standards of the American Gas Association, if mutually
agreed upon by the parties.
ARTICLE X
BILLING AND PAYMENTS
--------------------
10.1 On or before the fifteenth (15th) day of each calendar month,
Seller shall render a statement to Buyer giving the total volume and MMBTUS
of gas purchased and delivered hereunder during the preceding thirty (30)
day billing period, such statements to be rendered in accordance with this
Agreement.
10.2 Payment shall be made by Buyer to Seller on or bef ore the last
day of each calendar month or fifteen (15) days after the statement is
rendered, whichever is later.
10.3 All original statements, bills and payments submitted by either
party shall be subject to audit for any errors contained therein until the
expiration of two (2) years from the date appearing on such statements,
bills, and payments. Thereafter, all such statements, bills, and payments
shall be deemed correct, and all rights and claims thereunder forever
waived and released, unless a written claim f or a particular overpayment
or underpayment was made within said two(2) year period.
10.4 Should Buyer fail to pay any undisputed amount(s) due Seller
when the same is due, as provided herein, interest thereon shall accrue at
a rate equal to the then current prime rate of interest in effect at the
Citibank, New York, N.A., plus two percent (2%) from the date when such
payment was due until the same is fully paid. If any failure to pay
continues for sixty (60) days, Seller may suspend deliveries of gas
hereunder, and/or cancel this Agreement upon ten (10) days prior written
notice to Buyer, but the exercise of such right shall be in addition to any
and all other remedies available to Seller.
10.5 Each party shall have the right at all reasonable times to
examine the books, records and charts of the other party to the extent
necessary to verify the accuracy of any statement, charge, computation or
demand made under or pursuant to any of the provisions of this Agreement.
ARTICLE XI
SALE AND PASSAGE OF TITLE
-------------------------
11.1 Title to and possession of the gas sold and delivered hereunder
shall pass from Seller to Buyer at the outlet flange of Operator's or
Operator's designee's facilities at the applicable Delivery Point(s). As
between the parties hereto, Seller shall be in exclusive control and
possession of the gas deliverable hereunder and responsible for any damage
or injury caused thereby until the same shall have been delivered to Buyer
or its designee, after which Buyer shall be in exclusive control and
possession thereof and responsible for any damage or injury caused thereby.
ARTICLE XII
WARRANTY OF TITLE
-----------------
12.1 Seller warrants title to all gas delivered by it and warrants
that it has the right to sell the same and that such gas is free from liens
and adverse claims of every kind. Seller shall indemnify and save Buyer
harmless against all claims, suits, loss, damage, and expense of every kind
whatsoever, including without limitation any expense in the enforcement of
this indemnity, arising out of or on account of adverse claims to the gas
delivered hereunder or the proceeds due thereon from Buyer. If Seller's
title to gas hereunder or its right to receive proceeds hereunder is in any
manner questioned by any third party adverse claim of any character
whatsoever asserted with respect to any gas delivered or to be delivered to
Buyer hereunder, Buyer may withhold payments of sums due hereunder, with
interest, at the rate set forth in Paragraph 10.4 above, for such gas in
question until such adverse claim is withdrawn or finally adjudicated or
until Seller has furnished a bond, with sureties satisfactory to Buyer,
conditioned to hold Buyer harmless from such adverse claim.
ARTICLE XIII
FORCE MAJEURE
-------------
13.1 Each party hereto shall be excused from performing under this
Agreement, except for making payment for gas already delivered and received
hereunder, to the extent it is rendered unable to perform by a force
majeure situation, but only for the period of time such force majeure
situation continues. The term "force majeure" as employed herein and for
all purposes relating hereto shall mean acts of God, strikes, lockouts or
other industrial disturbances, acts of the public enemy, wars, blockades,
insurrections, riots, epidemics, landslides, lightning, earthquakes, fires,
storms, hurricane warnings, crevasses, floods, washouts, arrests and
restraints of governments and people, civil disturbances, explosions,
breakages or accident to machinery or lines of pipe, the necessity for
making repairs or alterations to machinery or lines of pipe, freezing of
wells or lines of pipe, partial or entire failure of wells, inability of
any party hereto to obtain necessary materials, supplies, or permits due to
existing or future rules, regulations, orders, laws or proclamations of
governmental authorities (both federal and state), including both civil and
military; the binding order of any court; acts of public authorities;
inability to obtain, transport or deliver, or delay in obtaining,
transporting or delivering supplies of gas by Seller to Buyer or
by Buyer to its markets as a result of any federal, state or local law or
any order, rule or regulation of governmental authority, both civil and
military including but not by way of limitation, any actions by a court
of competent jurisdiction or by FERC affecting price or gas supply and/or
with respect to the 1990 Supplemental Stipulation and Agreement by and
between Seller and Colorado Interstate Gas Company now pending in FERC
Docket Nos. RP79-59 and/or RP90-69; any failure by third-party transporters
to deliver Seller's gas to Buyer's facilities or thereafter to transport
gas for Buyer, and any other causes whether of the kind herein enumerated
or otherwise, not within the control of the party claiming suspension and
which by the exercise of due diligence such party is unable to prevent or
overcome; such term shall likewise include (a) the inability of such party
to acquire, or the delays on the part of such party in acquiring, at
reasonable cost and after the exercise of due diligence, any necessary
servitudes, right-of-way grants, permits or licenses, and (b) the inability
of each party to acquire, or the delays on the part of such party in
acquiring at reasonable cost and after the exercise of due diligence, any
necessary materials and supplies, permits and permissions.
13.2 The causes or contingencies set forth in Paragraph 13.1 above,
affecting performance shall not relieve Seller or Buyer of liability in the
event of failure of either to use due diligence to remedy the situation and
remove the cause in an adequate manner and with all reasonable dispatch,
nor shall such cause or contingencies relieve either party from its
obligations to make payments of amounts then due hereunder.
13.3 In the event of either Buyer or Seller being rendered unable
wholly or in part by force majeure to carry out its obligations under this
Agreement, it is agreed that on such party giving notice and full
particulars of such force majeure in writing to the other party as soon as
possible after the occurrence of the cause relied on, then the obligations
of the parties insofar as they are affected by such force majeure shall be
suspended during the continuance of any inability so caused but for no
longer period, and such cause shall as far as possible be remedied with all
reasonable dispatch.
ARTICLE XIV
GOVERNMENTAL AUTHORIZATIONS
---------------------------
14.1 This Agreement shall be subject to all valid and applicable laws
of the United States and of the state wherein it is to be performed, and to
the applicable valid rules, regulations or orders of any regulatory agency
or governmental authority having jurisdiction, and the parties shall be
entitled to regard all applicable laws, rules and regulations (federal,
state or local) as valid and may act in accordance therewith until such
time as the same may be declared invalid by final judgment of a court of
competent jurisdiction.
14.2 Notwithstanding any other provision of this Agreement to the
contrary, Seller shall not tender and Buyer shall not be obligated to
accept, transport or cause to be transported, or receive gas hereunder if
such act would subject Buyer or its designee to regulation or jurisdiction
of FERC under the Natural Gas Act of 1938, or any successor legislation
ARTICLE XV
INDEMNIFICATION
---------------
15.1 Buyer and Seller shall each indemnify, defend, and save harmless
the other including the other's employees and agents from and against any
and all loss, damage, injury, liability, and claims for injury to or death
of persons (including any employee of Buyer or Seller), or for loss or
damage to property (including the property of Buyer or Seller), resulting
directly or indirectly from the indemnifying party's performance of its
respective obligations arising pursuant to his Agreement (including the
installation, maintenance, and operation of property, equipment, and
facilities) or any other operations under this Agreement.
ARTICLE XVI
ASSIGNMENTS
-----------
16.1 Any successor, representative, or assignee which shall succeed
by purchase, merger or consolidation of either Seller or Buyer, as the case
may be, shall be entitled to the rights and shall be subject to the
obligations of its predecessor in title under this Agreement. Either party
may assign or pledge this Agreement under the provisions of any mortgage,
deed of trust, indenture or similar instrument which it has executed or may
execute hereafter. Otherwise, neither party shall assign this Agreement or
any of its rights, duties, or obligations hereunder unless it shall have
first obtained the consent (not be unreasonably withheld) in writing of the
other party hereto except in the case of corporate parents, affiliates, and
subsidiaries.
ARTICLE XVII
ROYALTY
-------
17.1 Buyer and Seller hereby agree that as between Seller and Buyer,
Seller is responsible for the payment of all royalty, overriding royalty
and production rights derived from the sale of gas hereunder to the parties
legally entitled thereto.
ARTICLE XVIII
NOTICES
-------
18.1 Any notice, request, demand, statement, or payment provided for
in this Agreement shall be in writing and shall be deemed delivered as of
the postmarked date when deposited in the United States mail, postage
prepaid, by first class, registered or certified addressed to the parties
as follows:
Notices: Payments:
-------- ---------
SELLER: Mesa operating Co. Mesa Operating Co.
5205 North O'Connor Blvd P. 0. Box 910148
Suite 1400 Dallas, Texas 75391-0148
Irving, Texas 75039-3746
Telephone: (214) 444-9001
Telecopy: (214) 444-4394
Attention: Marketing Department
BUYER: KN Marketing, L.P.
333 Clay, Suite 2000
Houston, Texas 77002
Telephone: (713) 739-2900
Telecopy: (713) 739-6696
Attention: Contract Administration
or at such other address as either party from time to time
designates for each purpose.
ARTICLE XIX
TAXES
-----
19.1 Seller shall pay or cause to be paid all taxes applicable to the
gas at or prior to delivery hereunder, now or hereafter required by law to
be paid to government authorities. Buyer shall pay or cause to be paid,
all taxes applicable to the gas subsequent to delivery hereunder, now or
hereafter required by law to be paid to government authorities. The term
"taxes," as used herein, shall mean all taxes, licenses, fees or charges
levied, assessed or made by any governmental authority on the act, right or
privilege of production, severance, gathering, transportation, handling,
sale or delivery of gas which is measured by the volume, value or sales
price of the gas imposed upon Seller or Buyer with respect to the gas
delivered hereunder. It is agreed that Buyer may, but is not obligated to,
remit to the governmental authority on behalf of Seller the taxes levied or
collected on gas produced and delivered to Buyer under this Agreement.
Buyer shall deduct any taxes remitted directly by Buyer on behalf of Seller
from amounts otherwise payable to Seller hereunder.
ARTICLE XX
MISCELLANEOUS
-------------
20.1 No waiver by either party of any one or more defaults by the
other in the performance of any provisions of this Agreement shall operate
or be construed as a waiver of any other default or defaults, whether of a
like or of a different character.
20.2 ANY INTERPRETATION HEREOF OR CONTROVERSY ARISING HEREUNDER SHALL
BE GOVERNED BY THE LAWS OF THE STATE OF TEXAS, EXCEPT ANY PROVISIONS OF
SUCH LAWS THAT WOULD REQUIRE THE APPLICATION OF THE LAW OF ANOTHER STATE.
In the event that any dispute hereunder or any breach or alleged breach of
any of the provisions hereof by either party results in a lawsuit being
filed, then the losing party in any such suit shall pay the reasonable
attorneys fees, professional expert fees, and court costs incurred by the
prevailing party. Each party waives any rights to or claims for punitive
or consequential damages arising from any breach of or dispute under this
Agreement.
20.3 This Agreement may be executed in any number of counterparts, no
one of which need be executed by all parties, and it shall be binding upon
all parties who execute a counterpart with the same force and effect and to
the same extent as if all such parties had executed and signed the same
document with each separate counterpart deemed to be an original.
20.4 This Agreement constitutes the entire agreement between the
parties and no waiver, representation or agreement, oral or otherwise,
shall effect the subject matter hereof unless and until such waiver,
representation or agreement is reduced to writing and executed by the
authorized representative of the parties.
20.5 Seller and Buyer shall not publish, disclose, or otherwise
divulge to any entity or person, except necessary officers, employees, and
agents of either party, at any time, either during or after the term of
this Agreement, nor shall either party permit any of its officers,
employees, or agents, to publish, disclose, or otherwise divulge, any
information concerning the terms of Article IV Price. This paragraph shall
-----
not preclude either party upon prior written notice to the other party from
revealing or using any information concerning the terms of Article IV
Price:
- -----
a) in filing reports with or furnishing information to the Securities
and Exchange Commission, securities commission of the various
states, or other appropriate governmental authorities, or
b) when advised by legal counsel that disclosure is required.
20.6 All terms and conditions of this Agreement were prepared jointly
by the parties hereto and not by any party to the exclusion of the other.
20.7 Although this Agreement is intended by the parties not to
benefit any third parties and shall not do so, this Agreement shall be
binding upon and inure to the benefit of the parties hereto and their
respective representatives, successors and assigns.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to
be duly executed as of the day and year first written above.
SELLER
MESA OPERATING CO.
By: /s/ Paul W. Cain
-----------------------------------------
Signature
Name: Paul W. Cain
--------------------------------------
Typed/Printed
Title: President and Chief Operating Officer
-------------------------------------
BUYER
KN MARKETING, L.P.
By its General Partner,
American Pipeline Company
By: /s/ S. H. Charlton, III
----------------------------------------
Signature
Name: Samuel H. Charlton, III
-------------------------------------
Typed/Printed
Title: Senior Vice President
-----------------------------------
<PAGE>
EXHIBIT "A"
Seller's customers which were receiving
gas from Seller as of January 1, 1995.
ENERGAS:
Base Agreement and CNG
ENERMART:
Weyerhauser Paper Co., Valley Proteins,
City of Amarillo, Water Treatment,
Crouse-Hinds, Farmland, and various
irrigation customers
*The sales volume from the TDCJ sale by
Energas may be added to the Enermart sale
at some later date.
IBP INC.
KN MARKETING, L.P.:
ASARCO
Pantex
<PAGE>
June 20, 1995
Mr. Samuel H. Charlton III
KN Marketing, L.P.
323 Clay St., Suite 2000
Houston TX 77002-9817
Gentlemen:
Re: Gas Purchase Agreement Dated January 1, 1996
Reference is made to the Gas Purchase Agreement ("Agreement") dated January
1, 1996, between Mesa Operating Co., as Seller, and KN Marketing, L.P., as
Buyer, relating to the sale and purchase of certain volumes of excess gas.
For purposes of this Agreement, "B" Contract gas shall mean that gas which
seller receives under and by virtue of that certain agreement dated January
3, 1928 between the Amarillo Oil Company, predecessor in interest of the
Seller and Canadian River Gas Company, predecessor in interest to Colorado
Interstate Gas Company as amended from time to time (The "B" Contract").
In implementing the provisions of Paragraph 2.3 of Article II of the above-
referenced Agreement, both parties agree that all of the excess gas
delivered by Seller to Buyer will be ultimately consumed in the City of
Amarillo and its environs to the maximum extent practicable. With respect
to that portion, if any, of excess "B" Contract gas which is delivered by
Seller to Buyer under the Agreement and which Buyer sells or delivers
outside the City of Amarillo and its environs, Buyer hereby agrees that the
first gas from other sources which Buyer delivers into the City of Amarillo
and its environs, if any, shall be deemed to be a return of the excess "B"
Contract gas first delivered outside the City of Amarillo and its environs.
The return of all such gas by Buyer shall be reflected in the quarterly
statements Buyer provides to Seller. If the above sets forth your
understanding of our agreement, please sign both originals of this
Agreement and return one for our records.
Sincerely,
ACCEPTED AND AGREED TO
this 1st day of August, 1995.
--- ------
MESA OPERATING CO. KN MARKETING, L.P.
By its General Partner,
American Pipeline Company
By: /s/ Paul W. Cain By: /s/ S.H. Charlton, III
----------------- ----------------------
Paul W. Cain S. H. Charlton, III
President and Chief Senior Vice President
Operating Officer
September 12, 1995
KN Marketing, L.P.
323 Clay Street, Suite 2000
Houston TX 77002-9817
Attention: Mr. Samuel H. Charlton, III
Subject: Confidentiality Provision
Gas Purchase Agreement
Dated January 1, 1996
Pursuant to Paragraph 20.5 of Article XX, Miscellaneous, of the captioned
Gas Purchase Agreement ("Agreement") Mesa Operating Co. ("Mesa") and KN
Marketing, L.P. ("KN") agreed to hold in confidence and not disclose any
information concerning the terms of Article IV, Price, of the Agreement
except in certain specific situations described therein.
Mesa has decided to offer for sale its interests in the oil and gas wells
and leases subject to the Agreement. As part of their due diligence,
prospective purchasers of these interests will need to review the captioned
Agreement.
In view of the foregoing, Mesa hereby requests that KN consent to the
disclosure of the terms of the Agreement including Article IV, Price, to
the prospective purchasers of its interests covered thereby. Mesa will
have the prospective purchasers sign a Confidentiality Agreement under
which they will agree to keep the information obtained from Mesa,
including the terms of the Agreement, confidential and use such information
only for the purpose of evaluating the properties for a transaction with
Mesa.
Please indicate your consent to Mesa's disclosure of the terms of the
agreement by signing in the space provided below and returning one (1) copy
of this letter to me. Thank you for your cooperation and prompt response.
KN herein expressly withholds its consent if the prospective purchaser is
Southwestern Public Service Company(SPS), Atmos Energy Corporation (Atmos)
and/or any affiliates of either SPS or Atmos.
Sincerely, MESA OPERATING CO.
By: /s/ D'Nard A. Hemphill
----------------------
D'Nard A. Hemphill, Attorney-in-Fact
Accepted and Agreed to this 18th day of September 1995.
---- --------------
KN MARKETING, L.P.
By its general Partner,
American Pipeline Company
By: /s/ S.H. Charlton, III
-----------------------
S.H. Charlton, III
Senior Vice President
MESA INC.
--------
CHANGE IN CONTROL RETENTION/SEVERANCE PLAN
------------------------------------------
Introduction
------------
The Board of Directors of MESA Inc. considers the prevention of
the loss of employees and the avoidance of distraction of employees as a
result of an actual or contemplated Change in Control to be essential to
protecting and enhancing the best interests of the Corporation and its
shareholders. The Board also believes that during the pendency of a Change
in Control and the transition period thereafter, the Board should be able
to receive and rely on disinterested service from employees regarding the
best interests of the Corporation and its shareholders without concern that
employees might be distracted or concerned by personal uncertainties and
risks.
Accordingly the Board has determined that appropriate steps
should be taken to assure the Corporation and its affiliates of the
continued employment and attention and dedication to duty of their
employees and to seek to ensure the availability of their continued
service, notwithstanding a Change in Control.
Therefore, in order to fulfill the above purposes, the following
plan has been developed and is hereby adopted.
ARTICLE I
ESTABLISHMENT OF PLAN
---------------------
As of the Effective Date, the Corporation hereby establishes a
separation compensation plan to be known as the MESA Inc. Change in Control
Retention/Severance Plan, as set forth in this document.
ARTICLE II
DEFINITIONS
-----------
(a) Board. The Board of Directors of MESA Inc.
-----
(b) Change in Control. Any of the following events:
-----------------
(1) The acquisition by any individual, entity or group
(within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities
Exchange Act of 1934, as amended (the "Exchange Act")) (a "Person") of
beneficial ownership (within the meaning of Rule 13d-3 promulgated under
the Exchange Act) of 35% or more of either (i) the then outstanding shares
of common stock of the Corporation (the "Outstanding Corporation Common
Stock") or (ii) the combined voting power of the then outstanding voting
securities of the Corporation entitled to vote generally in the election of
directors (the "Outstanding Corporation Voting Securities"); provided,
however, that for purposes of this paragraph (1), the following
acquisitions shall not in and of themselves constitute a Change in Control
hereunder: (i) any acquisition of securities of the Corporation made
directly from the Corporation and approved by a majority of the directors
then comprising the Incumbent Board (as defined below), (ii) any
acquisition of beneficial ownership of a higher percentage of the
Outstanding Corporation Common Stock or the Outstanding Corporation Voting
Securities that results solely from the acquisition, purchase or redemption
of securities of the Corporation by the Corporation so long as such action
by the Corporation was approved by a majority of the directors then
comprising the Incumbent Board, or (iii) any acquisition by any corporation
pursuant to a transaction that complies with clauses (i), (ii) and (iii) of
paragraph (3) hereof; or
(2) Individuals who, as of May 16, 1995, constituted the
Board (the "Incumbent Board") cease for any reason to constitute at least a
majority of the Board; provided, however, that any individual becoming a
director subsequent to May 16, 1995 whose election, or nomination for
election by the Corporation's shareholders, was approved by a vote of at
least a majority of the directors then comprising the Incumbent Board shall
be considered as though such individual were a member of the Incumbent
Board, but excluding, for this purpose, any such individual (including,
without limitation, David H. Batchelder and Dorn Parkinson) whose initial
assumption of office occurs as a result of an actual or threatened election
contest (as such terms are used in Rule 14a-11 of Regulation 14A
promulgated under the Exchange Act) or other actual or threatened
solicitation of proxies or consents by or on behalf of a Person other than
the Board; or
(3) Consummation of a reorganization, merger or
consolidation or sale or other disposition of all or substantially all the
assets of the Corporation (a "Business Combination"), in each case, unless,
following such Business Combination, (i) all or substantially all of the
individuals and entities that were the beneficial owners, respectively, of
the Outstanding Corporation Common Stock and Outstanding Corporation Voting
Securities immediately prior to such Business Combination beneficially
owned, directly or indirectly, more than 75% of, respectively, the then
outstanding shares of common stock and the combined voting power of the
then outstanding voting securities entitled to vote generally in the
election of directors, as the case may be, of the corporation resulting
from such Business Combination (including, without limitation, a
corporation which as a result of such transaction owns the Corporation or
all or substantially all the Corporation's assets either directly or
through one or more subsidiaries) in substantially the same proportions as
their ownership, immediately prior to such Business Combination, of the
Outstanding Corporation Common Stock and Outstanding Corporation Voting
Securities, as the case may be, (ii) no Person (excluding any corporation
resulting from such Business Combination) beneficially owns, directly or
indirectly, 35% or more of, respectively, the then outstanding shares of
common stock of the corporation resulting from such Business Combination
(including, without limitation, a corporation which as a result of such
transaction owns the Corporation or all or substantially all the
Corporation's assets either directly or through one or more subsidiaries)
or the combined voting power of the then outstanding voting securities of
such corporation except to the extent that such ownership existed prior to
the Business Combination and (iii) at least a majority of the members of
the board of directors of the corporation resulting from such Business
Combination were members of the Incumbent Board at the time of the
execution of the initial agreement, or of the action of the Board,
providing for such Business Combination; or
(4) Approval by the shareholders of the Corporation of a
complete liquidation or dissolution of the Corporation.
(c) Code. The Internal Revenue Code of 1986, as amended from
----
time to time.
(d) Committee. The Compensation Committee of the Board.
---------
(e) Corporation. MESA Inc., a Texas corporation.
-----------
(f) Date of Termination. The date a Participant's employment
-------------------
is terminated.
(g) Defined Pay. A Participant's compensation for purposes
-----------
of the Plan, determined as follows for the following categories of
employees:
(i) Officers - The sum of (1) the Officer's highest
annual salary during the current and three calendar years preceding the
Effective Date and (2) his highest annual bonus during such three preceding
years;
(ii) Key Employees - the sum of (1) the Key Employee's
annual salary in effect at his Date of Termination (or if such salary has
been reduced following a Change in Control, his highest rate of annual
salary at any time since the Change in Control) and (2) the average bonus
paid to the Key Employee during the three calendar years preceding the
Effective Date;
(iii) Other Performance Bonus Plan Participants - The
amount determined in the same manner as for Key Employees;
(iv) All other Participants - The Participant's annual
salary or wages, including, where applicable, scheduled overtime, in effect
at his Date of Termination(or if the rate of such salary or wages has been
reduced following a Change in Control, the highest rate of annual salary or
wages in effect for such Participant at any time since the Change in
Control).
(h) Effective Date. August 22, 1995.
--------------
(i) Employee. Any regular full-time or part-time employee of
--------
an Employer. The term shall exclude all individuals retained as
independent contractors.
(j) Employer. The Corporation and each Subsidiary that has
--------
adopted the Plan pursuant to Article V hereof and that are listed on
Schedule C hereof, as it may be modified from time to time.
(k) Key Employees. The key employees of the Employers
-------------
identified on the attached Schedule A, as it may be modified from time to
time.
(l) Officers. The officers of the Employers identified on
--------
the attached Schedule A, as it may be modified from time to time.
(m) Other Performance Bonus Plan Participants. The
-----------------------------------------
individuals identified as such on the attached Schedule A, as it may be
modified from time to time.
(n) Participant. An individual who is designated as such
-----------
pursuant to Section 3.1.
(o) Plan. The MESA Inc. Change in Control
----
Retention/Severance Plan.
(p) Severance Benefit. A benefit to which a Participant may
-----------------
become entitled pursuant to Article IV hereof.
(q) Subsidiary. Any corporation or other entity in which the
----------
Corporation, directly or indirectly, holds a majority of the voting power
or profits or capital interest of such entity.
ARTICLE III
ELIGIBILITY
-----------
3.1 Participation. Each Employee of an Employer on the Effective
-------------
Date shall become a Participant in the Plan. Any individual who
subsequently becomes an Employee prior to a Change in Control shall become
a Participant on his or her date of hire.
3.2 Duration of Participation. A Participant shall cease to be a
-------------------------
Participant in the Plan as a result of an amendment or termination of the
Plan complying with Article VII of the Plan, or when he or she ceases to be
an Employee of any Employer, unless, at the time he or she ceases to be an
Employee, such Participant is entitled to payment of a Severance Benefit as
provided in the Plan. A Participant entitled to payment of a Severance
Benefit or any other amounts under the Plan shall remain a Participant in
the Plan until the full amount of the Severance Benefit and any other
amounts payable under the Plan have been paid to the Participant.
ARTICLE IV
SEVERANCE BENEFITS
------------------
4.1 Right to Severance Benefit. A Participant shall be entitled
--------------------------
to receive from his or her Employer Severance Benefits in accordance with
Section 4.3 if the Participant's employment by an Employer shall terminate
in any circumstance specified in Section 4.2(a), whether the termination is
voluntary or involuntary.
4.2 Termination of Employment.
-------------------------
(a) Terminations That Give Rise to Severance Benefits Under
-------------------------------------------------------
This Plan.
- ---------
(i) Except as set forth in subsection (b) below, any
termination of employment with an Employer by action of the Employer or any
of its affiliates (excluding any transfer to another Employer, but treating
as a termination of employment the sale of any assets or the stock of the
Participant's Employer, unless a plan covering the Participant with
benefits equivalent to those payable hereunder that recognizes that a
Change in Control has already occurred is adopted by the entity that
thereafter employs the Participant), at any time after a Change in Control
and before the second anniversary of a Change in Control, shall entitle a
Participant to a Severance Benefit in accordance with Section 4.3.
(ii) If, at any time after a Change in Control and
before the second anniversary of the Change in Control, a Participant's
duties, responsibilities or annual salary or bonus as an Employee are
diminished or reduced in any respect in comparison to the duties,
responsibilities and Defined Pay enjoyed by the Participant on the
Effective Date or, if later, the Participant's date of hire, he may
terminate his employment within 90 days of the occurrence of such reduction
and be entitled to a Severance Benefit in accordance with Section 4.3.
(iii) If, at any time after a Change in Control and
before the second anniversary of the Change in Control, a Participant is
required to be based at a location more than 35 miles from the location
where the Participant was based and performed services immediately prior to
a Change in Control, he may terminate his employment within 90 days of the
notice of such relocation and be entitled to a Severance Benefit in
accordance with Section 4.3.
(b) Terminations That Do Not Give Rise to Severance Benefits
--------------------------------------------------------
Under This Plan. If a Participant's employment is terminated for Cause, or
- ---------------
voluntarily by the Participant in the absence of any event described in
subsection (a)(ii) or (iii) of this Section 4.2, the Participant shall not
be entitled to a Severance Benefit under the Plan.
A termination for Cause shall have occurred where a
Participant is terminated because of:
(i) the willful and continued failure of the Participant to
perform substantially the Participant's duties with the Employer (other
than any such failure resulting from incapacity due to physical or mental
illness), after a written demand for substantial performance is delivered
to the Participant by the Board or a duly-elected officer of the
Corporation which specifically identifies the manner in which the Board or
the elected officer believes that the Participant has not substantially
performed the Participant's duties, or
(ii) the willful engaging by the Participant in illegal
conduct or gross misconduct which is materially and demonstrably injurious
to the Corporation.
For purposes of this provision, no act or failure to act, on the part of
the Participant, shall be considered "willful" unless it is done, or
omitted to be done, by the Participant in bad faith or without reasonable
belief that the Partic ipant's action or omission was in the best interests
of the Corporation. Any act, or failure to act, based upon authority given
pursuant to a resolution duly adopted by the Board or based upon the advice
of counsel for the Corporation shall be conclusively presumed to be done,
or omitted to be done, by the Participant in good faith and in the best
interests of the Corporation.
4.3 Severance Benefits.
------------------
(a) If a Participant's employment is terminated in
circumstances entitling him to a Severance Benefit as provided in Section
4.2(a), the Participant's Employer or the Corporation shall pay such
Participant, within ten days of the Date of Termination, a cash lump sum as
set forth in subsection (b) below.
(b) A Participant's Severance Benefit shall be a percentage
of the Participant's Defined Pay in accordance with the following table:
Category of Participant Percentage of Defined Pay
----------------------- -------------------------
Officers 200 percent
Key Employees 150 percent
Other Performance Bonus Plan Participants In accordance with
Schedule B
All other Participants In accordance with
Schedule B
4.4 Other Benefits Payable. The benefits payable hereunder shall
----------------------
be payable in addition to, and not in lieu of, all other accrued or vested
or earned but deferred compensation, rights, options or other benefits that
may be owed to a Participant upon or following termination, including but
not limited to earned but unused vacation, amounts or benefits payable
under any bonus or other compensation plan, stock option plan, stock
ownership plan, stock purchase plan, life insurance plan, health plan,
disability plan or similar or successor plan; provided, however, that the
benefits payable under this Plan shall be deemed to include any severance
pay or pay in lieu of notice required to be paid to such Participant under
applicable law. This Plan shall supersede and replace any severance pay
plan, program or arrangement that may previously have been adopted by any
Employer.
4.5 Certain Reduction of Payments by an Employer.
--------------------------------------------
(a) For purposes of this Section 4.5, (i) a "Payment" shall
mean any payment or distribution in the nature of compensation to or for
the benefit of a Participant, whether paid or payable pursuant to this Plan
or otherwise; (ii) "Separation Payment" shall mean a Payment paid or
payable pursuant to this Plan (disregarding this Section); (iii) "Net After
Tax Receipt" shall mean the Present Value of a Payment net of all taxes
imposed on a Participant with respect thereto under Sections 1 and 4999 of
the Code, determined by applying the highest marginal rate under Section 1
of the Code that applied to the Participant's taxable income for the
immediately preceding taxable year; (iv) "Present Value" shall mean such
value determined in accordance with Section 280G(d)(4) of the Code; and (v)
"Reduced Amount" shall mean the greatest aggregate amount of Separation
Payments which (a) is less than the sum of all Separation Payments and (b)
results in aggregate Net After Tax Receipts that are equal to or greater
than the Net After Tax Receipts that would result if the Participant were
paid the sum of all Separation Payments.
(b) Anything in this Agreement to the contrary
notwithstanding, in the event that a nationally recognized certified public
accounting firm designated by the Participant (the "Accounting Firm") shall
determine that receipt of all Payments would subject the Participant to tax
under Section 4999 of the Code, it shall determine whether some amount of
Separation Payments would meet the definition of a "Reduced Amount." If
the Accounting Firm determines that there is a Reduced Amount, the
aggregate Separation Payments shall be reduced to such Reduced Amount. All
fees payable to the Accounting Firm shall be paid solely by the
Participant's Employer.
(c) If the Accounting Firm determines that aggregate
Separation Payments should be reduced to the Reduced Amount, the Employer
shall promptly give the Participant notice to that effect and a copy of the
detailed calculation thereof, and the Participant may then elect, in his
sole discretion, which and how much of the Separation Payments shall be
eliminated or reduced (as long as after such election the Present Value of
the aggregate Separation Payments equals the Reduced Amount), and shall
advise the Employer in writing of his election within ten days of his
receipt of notice. If no such election is made by the Participant within
such ten-day period, the Employer may elect which of such Separation
Payments shall be eliminated or reduced (as long as after such election the
Present Value of the aggregate Separation Payments equals the Reduced
Amount) and shall notify the Participant promptly of such election. All
determinations made by the Accounting Firm under this Section shall be
binding upon the Employer and the Participant and shall be made within 60
days of a termination of employment of the Participant. As promptly as
practicable following such determination, the Employer shall pay to or
distribute for the benefit of the Participant such Separation Payments as
are then due to the Participant under this Plan and shall promptly pay to
or distribute for the benefit of the Participant in the future such
Separation Payments as become due to the Participant under this Plan.
(d) While it is the intention of the Employers to reduce the
amounts payable or distributable to the Participants hereunder only if the
aggregate Net After Tax Receipts to a Participant would thereby be
increased, as a result of the uncertainty in the application of Section
4999 of the Code at the time of the initial determination by the Accounting
Firm hereunder, it is possible that amounts will have been paid or
distributed by the Employer to or for the benefit of a Participant pursuant
to this Plan which should not have been so paid or distributed
("Overpayment") or that additional amounts which will have not been paid or
distributed by the Employer to or for the benefit of a Participant pursuant
to this Plan could have been so paid or distributed ("Underpayment"), in
each case, consistent with the calculation of the Reduced Amount hereunder.
In the event that the Accounting Firm, based upon the assertion of a
deficiency by the Internal Revenue Service against the Employer or the
Participant which deficiency the Accounting Firm believes has a high
probability of success, determines that an Overpayment has been made, any
such Overpayment paid or distributed by the Employer to or for the benefit
of a Participant shall be treated for all purposes as a loan to the
Participant which the Participant shall repay to the Employer together
with interest at the applicable federal rate provided for in Section
7872(f)(2) of the Code; provided, however, that no such loan shall be
deemed to have been made and no amount shall be payable by a Participant to
the Employer if and to the extent such deemed loan and payment would not
either reduce the amount on which the Participant is subject to tax under
Section 1 and Section 4999 of the Code or generate a refund of such taxes.
In the event that the Accounting Firm, based upon controlling precedent or
substantial authority, determines that an Underpayment has occurred, any
such Underpayment shall be promptly paid by the Employer to or for the
benefit of the Participant together with interest at the applicable federal
rate provided for in Section 7872(f)(2) of the Code.
4.6 Payment Obligation Absolute.
---------------------------
Subject to Section 4.5, the obligations of the Employers to pay
the Severance Benefits described in Section 4.3 shall be absolute and
unconditional and shall not be affected by any circumstances, including,
without limitation, any set-off, counterclaim, recoupment, defense or other
right which an Employer may have against any Participant. In no event
shall a Participant be obligated to seek other employment or take any other
action by way of mitigation of the amounts payable to a Participant under
any of the provisions of this Plan, nor shall the amount of any payment
hereunder be reduced by any compensation earned by a Participant as a
result of employment by another employer.
ARTICLE V
PARTICIPATING EMPLOYERS
-----------------------
This Plan may be adopted by any Subsidiary of the Corporation if
the Board approves such adoption. Upon such adoption, the Subsidiary shall
become an Employer hereunder and the provisions of the Plan shall be fully
applicable to the Employees of that Subsidiary who are Participants
pursuant to Section 3.1.
ARTICLE VI
SUCCESSOR TO EMPLOYER
---------------------
This Plan shall bind any successor of an Employer, substantially
all its assets or substantially all its businesses (whether direct or
indirect, by purchase, merger, consolidation or otherwise), in the same
manner and to the same extent that the Employer would be obligated under
this Plan if no succession had taken place.
In the case of any transaction in which a successor would not by
the foregoing provision or by operation of law be bound by this Plan, the
Corporation shall require such successor expressly and unconditionally to
assume and agree to perform an Employer's obligations under this Plan, in
the same manner and to the same extent that the Employer would be required
to perform if no such succession had taken place. The term "Employer," as
used in this Plan, shall mean the Employer as hereinbefore defined and any
successor or assignee to the business or assets which by reason hereof
becomes bound by this Plan.
ARTICLE VII
DURATION, AMENDMENT AND TERMINATION
-----------------------------------
7.1 Duration. If a Change in Control has not occurred, this Plan
--------
shall expire two years from the Effective Date, unless extended for an
additional period or periods by resolution adopted by the Board.
If a Change in Control occurs, this Plan shall continue in full
force and effect and shall not terminate or expire until all Participants
who become entitled to any payments hereunder shall have received such
payments in full and all adjustments required to be made pursuant to
Section 4.5 have been made.
7.2 Termination and Amendment. The Plan shall be subject to
-------------------------
amendment, change, substitution, deletion, revocation or termination
(collectively, "Amendment") by the Board at any time prior to a Change in
Control other than at the request of a third party who has taken steps
reasonably calculated to effect a Change in Control. After a Change in
Control, the Plan shall not be subject to Amendment in any respect which
adversely affects the rights of a Participant without the consent of that
Participant.
7.3 Form of Amendment. The form of any amendment of the Plan
-----------------
shall be a written instrument signed by any person authorized to sign by
the Board. An amendment of the Plan in accordance with the terms hereof
shall automatically effect a corresponding amendment to all Participants'
rights hereunder.
ARTICLE VIII
MISCELLANEOUS
-------------
8.1 Indemnification. If after a Change in Control a Participant
---------------
institutes any legal action in seeking to obtain or enforce, or is required
to defend in any legal action the validity or enforceability of, any right
or benefit provided by this Plan, the Corporation or the Employer will pay
for all actual legal fees and expenses reasonably incurred (as incurred) by
such Participant, regardless of the outcome of such action.
8.2 Employment Status. This Plan does not constitute a contract
-----------------
of employment or impose on the Participant's Employer any obligation to
retain the Participant as an Employee, to change or not change the status
of the Participant's employment, or to change the Corporation's policies or
those of its Subsidiaries regarding termination of employment.
8.3 Claim Procedure. If an Employee or former Employee makes a
---------------
written request alleging a right to receive benefits under this Plan or
alleging a right to receive an adjustment in benefits being paid under the
Plan, the Corporation shall treat it as a claim for benefits. All claims
for benefits under the Plan shall be sent to the President of the
Corporation and must be received within 30 days after termination of
employment. If the President determines that any individual who has
claimed a right to receive benefits, or different benefits, under the Plan
is not entitled to receive all or any part of the benefits claimed, he will
inform the claimant in writing of its determination and the reasons
therefor in terms calculated to be understood by the claimant. The notice
will be sent within 90 days of the claim unless the President determines
additional time, not exceeding 90 days, is needed. The notice shall make
specific reference to the pertinent Plan provisions on which the denial is
based, and describe any additional material or information that is
necessary. Such notice shall, in addition, inform the claimant what
procedure the claimant should follow to take advantage of the review
procedures set forth below in the event the claimant desires to contest the
denial of the claim. The claimant may within 90 days thereafter submit in
writing to the Corporation a notice that the claimant contests the denial
of his or her claim by the President and desires a further review. The
Corporation shall within 60 days thereafter review the claim and authorize
the claimant to appear personally and review pertinent documents and submit
issues and comments relating to the claim to the persons responsible for
making the determination on behalf of the Corporation. The Corporation
will render its final decision with specific reasons therefor in writing
and will transmit it to the claimant within 60 days of the written request
for review, unless the Corporation determines additional time, not
exceeding 60 days, is needed.
8.4 Validity and Severability. The invalidity or unenforceability
-------------------------
of any provision of the Plan shall not affect the validity or
enforceability of any other provision of the Plan, which shall remain in
full force and effect, and any prohibition or unenforceability in any
jurisdiction shall not invalidate or render unenforceable such provision in
any other jurisdiction.
8.5 Governing Law. The validity, interpretation, construction and
-------------
performance of the Plan shall in all respects be governed by the laws of
Texas, without reference to principles of conflict of law.
ARTICLE IX
BOARD APPROVAL AND EFFECTIVE DATE
---------------------------------
This Plan was adopted by the Board on August 22, 1995, to be
effective as of the date of adoption.
IN WITNESS WHEREOF, MESA Inc. has caused these presents to be
executed by its duly authorized officer in a number of copies, all of which
shall constitute one and the same instrument, which may be sufficiently
evidenced by any executed copy hereof, this ____ day of August, 1995.
MESA INC.
By: /s/ Boone Pickens
-----------------------------------
ATTEST:
- --------------------------
<PAGE>
MESA INC.
CHANGE IN CONTROL RETENTION/SEVERANCE PLAN
------------------------------------------
Schedule A--Participant Designations
------------------------------------
I. Officers
--------
Paul W. Cain President & Chief Operating Officer
Dennis E. Fagerstone Vice President-Exploration & Production
Stephen K. Gardner Vice President & Chief Financial
Officer
Andrew J. Littlefair Vice President-Public Affairs
William D. Ballew Controller
II. Key Employees
-------------
Ronald D. Bassett Manager-Executive Administration
R. Sean Brennan Manager-Tax
Robert W. Burrahm Executive Vice President & General
Manager-Garretson
Paul M. Cashion Manager-Employee Relations
George S. Dixon Production Superintendent (Onshore)
Kim A. Doud Senior Geologist
Thomas M. DuBose Production Superintendent (Gulf Coast)
Mohamed I. El-Hitamy Supervisor-Facilities
Henry F. Galpin Supervisor-Gas Processing
Sam A. Giovinco, Jr. Area Engineering Supervisor
Robert L. Goggins Supervisor-Operations Services
Edwin E. Hance Manager-Engineering & Development
G. Patrick Hawkins Geological Specialist
D'Nard A. Hemphill Manager-Gas Marketing
Steven R. King Executive Vice President & General
Manager-MEV
Keith H. Pickett Manager-Land
Gary M. Prescott Associate General Counsel
Richard D. Rhodes Supervisor-Engineering Services
Kenneth H. Sheffield, Jr. Area Engineering Supervisor
M. Garrett Smith Director-Financial Planning
Sam W. Steward Area Engineering Supervisor
Wayne A. Stoerner Supervisor-Financial & General
Accounting
Kenneth R. Story Manager-Information Services
Edgar E. St. James Manager-Exploration
Steven R. Tennison Supervisor-Spot Sales
III. Other Performance Bonus Plan Participants
-----------------------------------------
Ronald D. Andrews Energy Markets Analyst
Frank J. Barra Facilities Engineering Specialist
Brett A. Benardino Purchasing Coordinator
Murray N. Bennett Property Tax Administrator
Michael B. Carroll Supervisor-Tax
Glen C. Carson Financial Analyst
Theodore L. Cottrell Drilling Engineering Specialist
William T. Davis Reservoir Engineer II
Kevin A. Dentzer Senior Landman
Robert W. Ellis Supervisor-Revenue/Production
Accounting
Charles C. Gamble Vice President-Marketing/Special
Projects MEV
Linda Gilbreath Sr. Programmer Analyst
Malcolm H. Gorrie Director-Shareholder Services
Frank L. Gregg Facilities Specialist
Hugh Hardy Geologist II
Thomas H. Hawkins Senior Counsel
Troy A. Hoefer Reservoir Engineer I
Treva Hohmann Assistant Manager-Tax
Ann G. Holt Coordinator Financial Analysis
Vicky C. Holton Supervisor-Administrative Services
John E. Janbaz Geological Specialist
Kim H. Janzen Gas Processing Specialist
J. Andrew Juett Associate Geologist
Mark A. Kieber Supervisor-Manufacturing Services
Robert J. Kultgen Accounting Analyst
William R. McElya Drilling Superintendent
Jenny V. Robins Senior Reservoir Engineer
John R. Rogers Supervisor-Audit
Jack E. Rosser Communications Director & Speech Writer
David W. Simpson Senior Counsel
Michael J. Smith Production Engineer II
John V. Sobchak Director-Treasury Operations
Robert L. Stepp, Jr. Reservoir Engineer II
James E. White Geophysical Specialist
Hershal K. Wolfe Coordinator-Gas Transportation
Lewis E. Wygant Supervisor-Payroll
01/31/96 (replaces 12/29/95)
<PAGE>
MESA INC.
CHANGE IN CONTROL RETENTION/SEVERANCE PLAN
------------------------------------------
Schedule B--Severance Calculation Formulas
------------------------------------------
The severance pay entitlement for all employees (except for designated
Officers and Key Employees, both as defined in the Plan) is the sum of
three component calculations. The three components are (1) Age, calculated
in months as of the Date of Termination, (2) Service, calculated in months
as of the Date of Termination, and (3) Defined Pay*. The component
calculations are shown below. Each calculation produces a figure
representing a number of weeks of Defined Pay, the sum of which is the
recipient's entitlement under the Plan.
AGE COMPONENT
- -------------
Age Calculation
--- -----------
Less than 30 years 2 weeks
30 years through 39 years, 11 months 6 + [ (Age in months - 360)
x .0166 ] weeks
40 years through 49 years, 11 months 8 + [ (Age in months - 480)
x .0166 ] weeks
50 years through 59 years, 11 months 10 + [ (Age in months -
600) x .0166 ] weeks
60 years and over 12 + [ (Age in months -
720) x .0166 ] weeks
SERVICE COMPONENT
- -----------------
Formula Calculation
------- -----------
One week of Defined Pay per year Service in months x .0833
of service
SALARY COMPONENT
- ----------------
Formula Calculation
------- -----------
Two weeks of Defined Pay for each Defined Pay x .0002
$10,000 increment of Defined Pay
(prorated for partial increments)
* The severance pay calculations in accordance with these formulas cover
two groups of employees, Other Performance Bonus Plan Participants and all
other Participants (excluding those designated as Officers or Key
Employees). Defined Pay for each group is defined in the Plan.
<PAGE>
MESA INC.
CHANGE IN CONTROL RETENTION/SEVERANCE PLAN
------------------------------------------
Schedule C--Adopting Employers and Affiliates
---------------------------------------------
The following employers and affiliates adopt the subject Plan upon its
Effective Date.
MESA Inc.
MESA Operating Co.
MESA Transmission Co.
MESA Capital Corporation
Pioneer Production Corporation International
Pioneer Uravan, Inc.
Pioneer Natural Gas Company
MESA Offshore Royalty Partnership
Hugoton Management Company
Hugoton Capital Limited Partnership
Hugoton Capital Corporation
MESA Holding Co.
MESA Environmental Ventures Co.
Garretson Equipment Co., Inc.
8/21/95
<PAGE>
FIRST AMENDMENT TO THE MESA INC.
CHANGE IN CONTROL RETENTION/SEVERANCE PLAN
Effective as of August 22, 1995, the MESA Inc. Change in Control
Retention/Severance Plan is hereby amended as follows:
1. Article II(g)(i) is amended to read as follows:
"Officers - The sum of (1) the Officer's highest annual salary
during the current and three calendar years preceding the Effective Date
and (2) his highest annual bonus during such preceding three years;
provided, however, that in the case of an Officer who received compensation
from BTC Partners, Inc. ("BTC") at any time during such three-year period,
his Defined Pay shall be computed by adding the average of the bonuses paid
to him by BTC and his Employer during such period to his highest annual
salary from his Employer as determined under (1) above;"
2. Article II(g) is further amended by adding at the end thereof the
following sentence:
"A Participant's compensation for purposes of the Plan shall mean
compensation from his or her Employer, and it shall also include, where
applicable, bonuses paid to a Participant while he was employed by BTC."
3. Article II(i) is amended to read as follows:
"Employee. Any regular full-time or part-time employee of an
--------
Employer, other than T. Boone Pickens. The term also shall exclude all
individuals retained as independent contractors."
In all other respects the Plan is hereby affirmed and ratified.
IN WITNESS WHEREOF, MESA Inc. has caused this amendment to be
executed by its duly authorized officer this 20th day of October, 1995.
MESA INC.
By: /s/ Boone Pickens
-----------------
ATTEST:
/s/ G. Michael Prescott
- -----------------------
<PAGE>
SECOND AMENDMENT TO THE MESA INC.
CHANGE IN CONTROL RETENTION/SEVERANCE PLAN
Effective as of January 1, 1996, the MESA Inc. Change in Control
Retention/Severance Plan is hereby amended as follows:
1. The first sentence of Section 4.2(b) of the Plan is hereby amended
to read as follows:
"If a Participant's employment is terminated for Cause, or voluntarily
by the Participant in the absence of any event described in subsection
(a)(ii) or (iii) of this Section 4.2 or for any reason prior to a
Change in Control, the Participant shall not be entitled to a
Severance Benefit under the Plan."
2. Article V is hereby amended by adding the following thereto:
"At any time that an Employer ceases to be a Subsidiary prior to the
occurrence of a Change in Control, it shall no longer be a
participating Employer hereunder and its Employees shall no longer be
eligible to receive benefits under the Plan."
3. Article VI is hereby deleted and each succeeding Article is renumbered
accordingly.
In all other respects the Plan is hereby affirmed and ratified.
IN WITNESS WHEREOF, MESA Inc. has caused this amendment to be
executed by its duly authorized officer this [27th] day of February, 1996.
MESA INC.
By: /s/ Boone Pickens
-----------------
ATTEST:
/s/ G. Michael Prescott
- -----------------------
